**UNITEDSTATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington,D.C. 20549**

 

**FORM 10-K**

 

**(Mark One)**

 
| **ý** | ** ** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF  1934**                                       |
|------------|------------|---------------------------------------------------------------------------------------------------------------------------------------|
|       |       |                                                                                                                                  |
|       |       | **For the fiscal year ended December 31,  2004**                                                                                 |
|       |       |                                                                                                                                  |
| **OR**     |
|       |       |                                                                                                                                  |
| **o**      | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF  1934**                                   |
|       |       |                                                                                                                                  |
|       |       | **For the transition period  from        to        ** |

 

**COMMISSIONFILE NUMBER 000-31387**

 

**NORTHERN STATES POWER COMPANY**

(Exact name of registrant asspecified in its charter)

 

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

 

**414Nicollet Mall**

**Minneapolis,Minnesota 55401**

(Address of principal executiveoffices)

(Zip Code)

 

**(612)330-5500**

(Registrant’s telephone number,including area code)

 

Securities registered pursuantto Section 12(b) of the Act:**  None**

 

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

 

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

 

Indicate by check mark if disclosure ofdelinquent filers pursuant to Item 405 of Regulation S-K is not containedherein, and will not be contained, to the best of registrant’s knowledge, indefinitive proxy or information statements incorporated by reference in PartIII of this Form 10-K or any amendment to this Form 10-K. ý

 

Indicate by check mark whether the registrantis an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes  o  No ý

 

As of Feb. 28, 2005, 1,000,000 shares ofcommon stock, par value $0.01 per share, were outstanding, all of which wereheld by Xcel Energy Inc., a Minnesota Corporation.

 

**DOCUMENTSINCORPORATED BY REFERENCE: Xcel Energy Inc.’s 2005 Proxy Statement**

** **

**Northern States Power Company meets theconditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and istherefore filing this form with the reduced disclosure format permitted byGeneral Instruction I(2).**

 

 

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**INDEX**

 
| **PART I**                                                                                                 |   |
|------------------------------------------------------------------------------------------------------------|--------|
| Item 1 —  Business                                                                                    |   |
| DEFINITIONS                                                                                                |   |
| COMPANY OVERVIEW                                                                                           |   |
| ELECTRIC UTILITY OPERATIONS                                                                                |   |
| Summary  of Recent Regulatory Developments                                                                 |   |
| General Electric Utility Pending Regulatory Matters                                                        |   |
| Ratemaking Principles                                                                                      |   |
| Capacity and Demand                                                                                        |   |
| Energy  Sources                                                                                            |   |
| Fuel Supply and Costs                                                                                      |   |
| Trading Operations                                                                                         |   |
| Nuclear Power Operations and Waste Disposal                                                                |   |
| Electric  Operating Statistics                                                                             |   |
| NATURAL GAS UTILITY  OPERATIONS                                                                            |   |
| Summary of  Recent Regulatory Developments                                                                 |   |
| Ratemaking Principles                                                                                      |   |
| Capability and Demand                                                                                      |   |
| Natural Gas Supply and  Costs                                                                              |   |
| Natural  Gas Operating Statistics                                                                          |   |
| ENVIRONMENTAL MATTERS                                                                                      |   |
| EMPLOYEES                                                                                                  |   |
| Item  2 — Properties                                                                                  |   |
| Item 3 — Legal Proceedings                                                                            |   |
| Item  4 — Submission of Matters to a Vote of Security Holders                                         |   |
|                                                                                                       |   |
| **PART II**                                                                                                |   |
| Item  5 — Market for Registrant’s Common Equity and Related Stockholder Matters                  |   |
| Item 6 — Selected  Financial Data                                                                     |   |
| Item  7 — Management’s Discussion and Analysis of Financial Condition and Results  of Operations |   |
| Item  7A — Quantitative and Qualitative Disclosures About Market Risk                                 |   |
| Item  8 — Financial Statements and Supplementary Data                                                 |   |
| Item 9 —  Changes in and Disagreements with Accountants on Accounting and Financial  Disclosure       |   |
| Item 9A —  Controls and Procedures                                                                    |   |
| Item 9B —  Other Information                                                                          |   |
|                                                                                                       |   |
| **PART  III**                                                                                              |   |
| Item 10 —  Directors and Executive Officers of the Registrant                                         |   |
| Item 11 —  Executive Compensation                                                                     |   |
| Item 12 —  Security Ownership of Certain Beneficial Owners and Management                             |   |
| Item 13 —  Certain Relationships and Related Transactions                                             |   |
| Item 14 —  Principal Accounting Fees and Services                                                     |   |
|                                                                                                       |   |
| **PART IV**                                                                                                |   |
| Item 15 —  Exhibits, Financial Statement Schedules                                                    |   |
|                                                                                                       |   |
| **SIGNATURES**                                                                                             |   |

 

This Form 10-K is filed by Northern StatesPower Co., a Minnesota corporation (NSP-Minnesota). NSP-Minnesota is a whollyowned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy isavailable in various filings with the U.S. Securities and Exchange Commission(SEC).  This report should be read in itsentirety.

 

2

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**PARTI**

 

**Item l —Business**

 

# **DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel Energy Subsidiaries and Affiliates***              |   |                                                                                                                                                                                                                                                                                                                                                                                                                |
|------------------------------------------------------------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| NSP-Minnesota                                              |   | Northern  States Power Co., a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                 |
| NSP-Wisconsin                                              |   | Northern  States Power Co., a Wisconsin corporation                                                                                                                                                                                                                                                                                                                                                                 |
| PSCo                                                       |   | Public  Service Company of Colorado, a Colorado corporation                                                                                                                                                                                                                                                                                                                                                         |
| SPS                                                        |   | Southwestern  Public Service Co., a New Mexico corporation                                                                                                                                                                                                                                                                                                                                                          |
| Utility  Subsidiaries                                      |   | NSP-Minnesota,  NSP-Wisconsin, PSCo, SPS                                                                                                                                                                                                                                                                                                                                                                            |
| Xcel Energy                                                |   | Xcel Energy  Inc., a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                          |
|                                                       |   |                                                                                                                                                                                                                                                                                                                                                                                                                |
| ***Federal and State Regulatory Agencies***                |   |                                                                                                                                                                                                                                                                                                                                                                                                                |
| ASLB                                                       |   | Atomic  Safety and Licensing Board                                                                                                                                                                                                                                                                                                                                                                                  |
| DOE                                                        |   | United  States Department of Energy                                                                                                                                                                                                                                                                                                                                                                                 |
| DOL                                                        |   | United  States Department of Labor                                                                                                                                                                                                                                                                                                                                                                                  |
| EPA                                                        |   | United  States Environmental Protection Agency                                                                                                                                                                                                                                                                                                                                                                      |
| FERC                                                       |   | Federal  Energy Regulatory Commission. The U.S. agency that regulates the rates and  services for transportation of electricity and natural gas, and the sale of  electricity at wholesale, in interstate commerce, including the sale of  electricity at market-based rates.                                                                                                                                       |
| IRS                                                        |   | Internal  Revenue Service                                                                                                                                                                                                                                                                                                                                                                                           |
| MEQB                                                       |   | Minnesota  Environment Quality Board. Selects and designates sites for new power plants  (capacity of 50MW or more), wind energy conversion plants (capacity of 5MW or  more) and routes for electric transmission lines (capacity of 100KV or more)  in Minnesota.                                                                                                                                                 |
| MPUC                                                       |   | Minnesota  Public Utilities Commission. The state agency that regulates the retail  rates, services and other aspects of NSP-Minnesota’s operations in Minnesota.  The MPUC also has jurisdiction over the capital structure and issuance of  securities by NSP-Minnesota.                                                                                                                                     |
| NDPSC                                                      |   | North Dakota  Public Service Commission. The state agency that regulates the retail rates,  services and other aspects of NSP-Minnesota’s operations in North Dakota.                                                                                                                                                                                                                                          |
| NRC                                                        |   | Nuclear  Regulatory Commission. The federal agency that regulates the operation of  nuclear power plants.                                                                                                                                                                                                                                                                                                           |
| SDPUC                                                      |   | South Dakota  Public Utilities Commission. The state agency that regulates the retail  rates, services and other aspects of NSP-Minnesota’s operations in South  Dakota.                                                                                                                                                                                                                                       |
| SEC                                                        |   | Securities  and Exchange Commission                                                                                                                                                                                                                                                                                                                                                                                 |
|                                                       |   |                                                                                                                                                                                                                                                                                                                                                                                                                |
| ***Fuel, Purchased Gas and Resource Adjustment  Clauses*** |   |                                                                                                                                                                                                                                                                                                                                                                                                                |
| FCA                                                        |   | Fuel clause adjustment. A  clause included in NSP-Minnesota’s retail electric rate schedules that  provides for prospective monthly rate adjustments to reflect the forecasted  cost of electric fuel and purchased energy. The difference between the  electric costs collected through the FCA rates and the actual costs incurred  in a month are collected or refunded in a subsequent three-month period. |
| PGA                                                        |   | Purchased  gas adjustment. A clause included in NSP-Minnesota’s retail gas rate  schedules that provides for prospective monthly rate adjustments to reflect  the forecasted cost of purchased gas. The annual difference between the gas  costs collected through PGA rates and the actual gas costs is collected or  refunded over the subsequent 12-month period.                                           |

 

3

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| RCR                                 |   | Renewable cost recovery  adjustment. Allows NSP-Minnesota to recover the cost of transmission  facilities and other costs incurred to facilitate the purchase of renewable  energy (including wind energy) in retail electric rates in Minnesota. The RCR  is revised annually.                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|-------------------------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| ***Other Terms and Abbreviations*** |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| AFDC                                |   | Allowance  for funds used during construction. Defined in regulatory accounts as a  non-cash accounting convention that represents the estimated composite  interest costs of debt and a return on equity funds used to finance  construction. The allowance is capitalized in property accounts and included  in income.                                                                                                                                                                                                                                                                                                                                                                                                               |
| ALJ                                 |   | Administrative  law judge. A judge presiding over regulatory proceedings.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| ARO                                 |   | Asset  Retirement Obligation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| C20                                 |   | Derivatives  Implementation Group of FASB Implementation Issue No. C20. Clarified the  terms clearly and closely related to normal purchases and sales contracts, as  included in SFAS No. 133, as amended.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| Decommissioning                     |   | The process  of closing down a nuclear facility and reducing the residual radioactivity to  a level that permits the release of the property and termination of license.  Nuclear power plants are required by the NRC to set aside funds for their  decommissioning costs during operation.                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| Deferred  energy costs              |   | The amount  of fuel costs applicable to service rendered in one accounting period that  will not be reflected in billings to customers until a subsequent accounting  period.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| Derivative  instrument              |   | A financial  instrument or other contract with all three of the following characteristics:

•      An  underlying and a notional amount or payment provision or both,

•      Requires  no initial investment or an initial net investment that is smaller than would  be required for other types of contracts that would be expected to have a  similar response to changes in market factors, and

•      Terms  require or permit a net settlement, can be readily settled net by means  outside the contract or provides for delivery of an asset that puts the  recipient in a position not substantially different from net settlement |
| Distribution                        |   | The system  of lines, transformers, switches and mains that connect electric and natural  gas transmission systems to customers.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| ERISA                               |   | Employee  Retirement Income Security Act                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| FASB                                |   | Financial  Accounting Standards Board                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| FTRs                                |   | Financial  Transmission Rights                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| GAAP                                |   | Generally  accepted accounting principles                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| Generation                          |   | The process  of transforming other forms of energy, such as nuclear or fossil fuels, into  electricity. Also, the amount of electric energy produced, expressed in  megawatts (capacity) or megawatt hours (energy).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| JOA                                 |   | Joint  operating agreement among the Utility Subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| LDC                                 |   | Local  distribution company. A company or division that obtains the major portion of  its revenues from the operations of a retail distribution system for the  delivery of electricity or natural gas for ultimate consumption.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| LIBOR                               |   | London  Interbank Offered Rate                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| LNG                                 |   | Liquefied  natural gas. Natural gas that has been converted to a liquid by cooling it to  – 260 degrees Fahrenheit.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| Mark-to-market                      |   | The process  whereby an asset or liability is recognized at fair value and the change in  the fair value of that asset or liability is recognized in current earnings  in the Consolidated Statements of Operations or in Other Comprehensive Income  within equity during the current period.                                                                                                                                                                                                                                                                                                                                                                                                                                          |

 

4

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| MERP                      |         | Metropolitan  emissions reduction project.                                                                                                                                                                                                                            |
|---------------------------|--------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| MGP                       |         | Manufactured  gas plant.                                                                                                                                                                                                                                              |
| MISO                      |         | Midwest  Independent Transmission System Operator, Inc.                                                                                                                                                                                                               |
| Native load               |         | The customer  demand of retail and wholesale customers whereby a utility has an obligation  to serve: e.g., an obligation to provide electric or natural gas service  created by statute or long-term contract.                                                       |
| Natural gas               |         | A naturally  occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous  geological formations beneath the earth’s surface, often in association with  petroleum. The principal constituent is methane.                                          |
| Nonutility                |         | All items of  revenue, expense and investment not associated, either by direct assignment  or by allocation, with providing service to the utility customer.                                                                                                          |
| OMOI                      |         | FERC Office  of Market Oversight and Investigations                                                                                                                                                                                                                   |
| PFS                       |         | Private Fuel  Storage, LLC. A consortium of private parties (including  NSP-Minnesota) working to establish a private facility for interim storage of  spent nuclear fuel.                                                                                            |
| PJM                       |         | PJM Interconnection, Inc.                                                                                                                                                                                                                                             |
| PUHCA                     |         | Public  Utility Holding Company Act of 1935. Enacted to regulate the corporate  structure and financial operations of utility holding companies. Applies to  companies that own or control 10% or more of a utility.                                                  |
| 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 utilities’ electric transmission systems, in  order to provide non-discriminatory access to transmission of electricity.         |
| SFAS                      |         | Statement of  Financial Accounting Standards                                                                                                                                                                                                                          |
| SMA                       |         | Supply  margin assessment                                                                                                                                                                                                                                             |
| SMD                       |         | Standard  market design                                                                                                                                                                                                                                               |
| SO2                       |         | Sulfur  dioxide                                                                                                                                                                                                                                                       |
| TEMT                      |         | Transmission  and Energy Markets Tariff                                                                                                                                                                                                                               |
| Unbilled  revenues        |         | Amount of  service rendered but not billed at the end of an accounting period. Cycle  meter-reading practices result in unbilled consumption between the date of  last meter reading and the end of the period.                                                       |
| Underlying                |         | A specified  interest rate, security price, commodity price, foreign exchange rate, index  of prices or rates, or other variable, including the occurrence or  nonoccurrence of a specified event such as a scheduled payment under a  contract.                      |
| VaR                       |         | Value-at-risk                                                                                                                                                                                                                                                         |
| Wheeling or  Transmission |         | An electric  service wherein high voltage transmission facilities of one utility system  are used to transmit power generated within or purchased from another system.                                                                                                |
| Working  capital          |         | Funds  necessary to meet operating expenses                                                                                                                                                                                                                           |
|                      |         |                                                                                                                                                                                                                                                                  |
| ***Measurements***        | *** *** | *** ***                                                                                                                                                                                                                                                          |
| Btu                       |         | British  thermal unit. A standard unit for measuring thermal energy or heat commonly  used as a gauge for the energy content of natural gas and other fuels.                                                                                                          |
| Bcf                       |         | Billion  cubic feet                                                                                                                                                                                                                                                   |
| Dth                       |         | Dekatherm  (one Dth is equal to one MMBtu)                                                                                                                                                                                                                            |

 

5

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| KV    |   | Kilovolts                                                                                                                                                                    |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| KW    |   | Kilowatts                                                                                                                                                                    |
| Kwh   |   | Kilowatt  hours                                                                                                                                                              |
| MMBtu |   | One million  BTUs                                                                                                                                                            |
| MW    |   | Megawatts  (one MW equals one thousand KW)                                                                                                                                   |
| Mwh   |   | Megawatt  hour. One Mwh equals one thousand Kwh.                                                                                                                             |
| Watt  |   | A measure of  power production or usage equal to the kinetic energy of an object with a  mass of 2 kilograms moving with a velocity of one meter per second for one  second. |

 

6

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# **COMPANYOVERVIEW**

 

NSP-Minnesota wasincorporated in 2000 under the laws of Minnesota. Prior to 2000, the regulatedutility operations were conducted by the legal entity now operating under thename Xcel Energy, Inc. NSP-Minnesota is an operating utility engaged in thegeneration, purchase, transmission, distribution and sale of electricity inMinnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, distributes and sells natural gas toretail customers and transports customer-owned natural gas in Minnesota andNorth Dakota.  NSP-Minnesota provideselectric utility service to approximately 1.4 million customers and gas utilityservice to approximately 454,000 customers.

 

The electricproduction and transmission system of NSP-Minnesota is managed as an integratedsystem with that of NSP-Wisconsin, jointly referred to as the NSP System. Theelectric production and transmission costs of the entire NSP System are sharedby NSP-Minnesota and NSP-Wisconsin.  AFERC approved agreement between the two companies, called the InterchangeAgreement, provides for the sharing of all costs of generation and transmissionfacilities of the NSP System, including capital costs.

 

NSP-Minnesotaowns the following direct subsidiaries: United Power and Land Co., which holdsreal estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in theNuclear Management Co. (NMC). NSP-Minnesota owned NSP Financing I, a special purpose financing trust,for which a certificate of cancellation was filed for dissolution on Sept. 15,2003.  NSP-Minnesota is a wholly ownedsubsidiary of Xcel Energy.

 

Xcel Energy was incorporatedunder the laws of Minnesota in 1909 and is a registered holding company underthe PUHCA. Xcel Energy is subject to the regulatory oversight of the SEC underPUHCA. The rules and regulations under PUHCA impose a number of restrictions onthe operations of registered holding company systems. These restrictionsinclude, subject to certain exceptions, a requirement that the SEC approvesecurities issuances, payments of dividends out of capital or unearned surplus,sales and acquisitions of utility assets or of securities of utility companiesand acquisitions of other businesses. PUHCA also generally limits theoperations of a registered holding company to a single integrated publicutility system, plus additional energy-related businesses. PUHCA rules requirethat transactions between affiliated companies in a registered holding companysystem be performed at cost, with limited exceptions.

 

In 2004, Xcel Energycontinuing operations included the activity of four wholly owned utilitysubsidiaries, including NSP-Minnesota, that serve electric and natural gascustomers in 10 states. The other utility subsidiaries are NSP-Wisconsin, PSCoand SPS. These utilities serve customers in portions of Colorado, Kansas,Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texasand Wisconsin.

 

# **ELECTRIC UTILITY OPERATIONS**

# ** **

**Overview**

 

***Utility Industry Growth***—After a decade of cost cutting and efficiency gains in anticipation of industryrestructuring and competition, areas of growth for the utility industry arelimited.  The most significant areas forearnings growth include increasing regulated rates, increased investment inrate base, diversification, acquisition or modification of rate structures toimplement performance-based rates. NSP-Minnesota intends to focus on growing through investments in electric and natural gas ratebase to meet growing customer demands and to maintain or increase reliabilityand quality of service to customers and rate case filings with state andfederal regulators to increase rates congruent with increasing costs ofoperations associated with such investments.

 

***Utility Restructuring and RetailCompetition***— The structure of the utility industry hasbeen subject to change.  Merger andacquisition activity in the past had been significant as utilities combined tocapture economies of scale or establish a strategic niche in preparing for thefuture, although such activity slowed substantially after 2001.  All investor-owned utilities were required toprovide nondiscriminatory access to the use of their transmission systems in1996.  Beginning in the late 1990s, manystates began studying or implementing some form of retail electric utilitycompetition.  As a result of the failureof the California power market structure and nonregulated investments of manyutilities, as well as other factors, most utility retail market restructuring hasceased.  No significant activity hasoccurred or is expected to occur in any of the retail jurisdictions in whichNSP-Minnesota operates.

 

Theretail electric business does face some competition as industrial and largecommercial customers have some ability to own or operate facilities to generatetheir own electricity. In addition, customers may have the option ofsubstituting other fuels, such as natural gas or steam/chilled water forheating, cooling and manufacturing purposes, or the option of relocating theirfacilities to a lower cost region.  WhileNSP-Minnesota faces these challenges, it believes its rates are competitivewith currently available

 

7

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alternatives.

 

# **Summaryof Recent Federal Regulatory Developments**

 

TheFERC has jurisdiction over rates for electric transmission service ininterstate commerce and electric energy sold at wholesale, hydro facilitylicensing, accounting practices and certain other activities ofNSP-Minnesota.  State and local agencieshave jurisdiction over many of NSP-Minnesota’s activities, including regulationof retail rates and environmental matters.

 

***Market Based Rate Authority***— The FERC regulates the wholesale sale ofelectricity.  In addition to FERC’straditional cost of service methodology for determining the rates allowed to becharged for wholesale electric sales, in the 1990’s FERC began to allowutilities to make sales at market-based rates. In order to obtain market-based rate authorization from the FERC,utilities such as NSP-Minnesota, have been required to submit analysesdemonstrating that they did not have market power in the relevant markets.  NSP-Minnesota has been authorized by FERC tomake wholesale sales at market-based rates.

 

In November 2001, afterthe market disruptions in California and other regions, the FERC issued anorder under Section 206 of the Federal Power Act initiating a genericinvestigation proceeding against all jurisdictional electric suppliers makingsales in interstate commerce at market-based rates.  In November 2003, the FERC issued afinal order requiring amendments to the market-based wholesale tariffs of allFERC jurisdictional electric utilities to impose new market behavior rules andrequiring submission of compliance tariff amendments in December 2003.  NSP-Minnesota made a timely compliancefiling.  Violations of the new tariffscould result in the loss of certain wholesale sales revenues or the loss ofauthority to make sales at market-based rates.

 

In 2004, FERC initiated anew proceeding on future market-based rate authorizations and issued interimrequirements for FERC jurisdictional electric utilities that have been grantedauthority to make wholesale sales at market-based rates.  The FERC adopted a new interim methodology toassess generation market power and modified measures to mitigate market powerwhere it is found.  The FERC upheld andclarified the interim requirements on rehearing in an order issued on July 8,2004.  This methodology is to be appliedto all initial market-based rate applications and triennial reviews.  Under this methodology, the FERC has adoptedtwo indicative screens (an uncommitted pivotal supplier analysis and anuncommitted market share analysis) to assess market power.  Passage of the two screens creates arebuttable presumption that an applicant does not have market power, while thefailure creates a rebuttable presumption that the utility does have marketpower.  An applicant or intervenor canrebut the presumption by performing a more extensive delivered-price testanalysis.  If an applicant is determinedto have generation market power, the applicant has the opportunity to proposeits own mitigation plan or may implement default mitigation established by theFERC.  The default mitigation limitsprices for sales of power to cost-based rates within areas where an applicantis found to have market power.

 

As required by the FERC,Xcel Energy filed the required analysis applying the FERC’s two indicativescreens on behalf of itself and the Utility Subsidiaries with the FERC on Feb.7, 2005.  This analysis demonstrated thatNSP-Minnesota passed the pivotal supplier analysis in its own control area andall adjacent markets, but that it failed the market share analysis in its owncontrol area, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointlyoperate a single control area and accordingly are analyzed as one company, incertain adjacent markets.  It isaccordingly expected that the FERC will set the market-rate authorizations forNSP-Minnesota for investigation and hearing under Section 206 of theFederal Power Act.  At that time,NSP-Minnesota expects to submit a delivered-price test analysis to support thecontinuance of market-based rate authority in its control areas.  NSP-Minnesota also expects that upon thecommencement of the MISO Day 2 market (see Electric Transmission RateRegulation, below for further discussion), NSP-Minnesota and NSP-Wisconsin willbe analyzed as part of the larger MISO market, and that those companies willpass both of the FERC’s indicative screens in the larger MISO market.  NSP-Minnesota does not expect the mitigationmeasures imposed, if any, to have a significant financial impact on itscommodity marketing operations.

 

In order to enable it andinterested parties to monitor each individual utility’s market-based rateauthority, the FERC on Feb. 10, 2005 issued a final rule requiring that autility with market-based rate authority file reports notifying the FERC ofchanges in status (*e.g.*,additions of certain generating resources) that reflect a departure from thecharacteristics that the FERC relied upon in granting that utility market-basedrate authority within thirty days of the occurrence of a triggering event.

 

8

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***Electric Transmission Rate Regulation***— The FERC also regulates the rates chargedand terms and conditions for electric transmission services.  Since 1996, the FERC has requiredNSP-Minnesota to provide open access transmission service at rates and tariffson file with the FERC.  In addition, FERCpolicy encourages utilities to turn over the functional control over theirelectric transmission assets and the related responsibility for the sale ofelectric transmission services to an RTO. NSP-Minnesota is a member of the MISO, which began RTO operations inearly 2002.  Each RTO separately filesfor regional transmission tariff rates for approval by FERC.  All members within that RTO are thensubjected to those rates.

 

***Generation Interconnection Rules —***In August 2003, the FERC issued finalrules requiring the standardization of generation interconnection proceduresand agreements for interconnection of new electric generators of 20 megawattsor more to the transmission systems of all FERC-jurisdictional electricutilities, including NSP-Minnesota. The FERC also established pricing rules forinterconnections and related transmission system upgrades, which allow thetransmission-owning utility to require the interconnecting customer to fund theinterconnection costs and network upgrades required by the new generator, butrequire the transmission utility to provide transmission service credits, withinterest, for the full amount of prepayment. The FERC required compliancefilings for detailing proposed changes to NSP-Minnesota’s tariff and the MISOregional tariff, which will govern most generation interconnections to theNSP-Minnesota transmission system.  InOctober 2004, the FERC accepted proposed tariff changes for NSP-Minnesota,subject to certain conditions.  In November 2004,NSP-Minnesota submitted a compliance filing. In December 2004, the FERC issued further modifications to theinterconnection rules on rehearing and required NSP-Minnesota to submit afurther compliance filing by February 2005.  The required compliance filing was submittedon Feb. 18, 2005.

 

**RatemakingPrinciples**

 

***Summary of Regulatory Agencies and Areas of Jurisdiction***— Retail rates, services and other aspects ofNSP-Minnesota’s operations are subject to the jurisdiction of the MPUC, theNDPSC and the SDPUC within their respective states. The MPUC has regulatoryauthority over aspects of NSP-Minnesota’s financial activities, includingsecurity issuances, certain property transfers, mergers with other utilitiesand transactions between NSP-Minnesota and its affiliates. In addition, theMPUC reviews and approves NSP-Minnesota’s electric resource plans for meetingcustomers’ future energy needs. The MPUC also certifies the need for generatingplants greater than 50 MW and transmission lines greater than 100 KV. NSP-Minnesotais subject to the jurisdiction of the FERC with respect to its wholesaleelectric operations, accounting practices, wholesale sales for resale and thetransmission of electricity in interstate commerce. NSP-Minnesota has receivedauthorization from the FERC to make wholesale electric sales at market-basedprices and is a transmission-only member of the MISO RTO.

 

The MEQB is empowered toselect and designate sites for new power plants with a capacity of 50 MW ormore and wind energy conversion plants with a capacity of five MW or more. Italso designates routes for electric transmission lines with a capacity of 100KV or more. No power plant or transmission line may be constructed in Minnesotaexcept on a site or route designated by the MEQB.  The NDPSC and SDPUC have regulatory authorityover the need for certain generating and transmission facilities, and thesiting and routing of certain new generation and transmission facilities inNorth Dakota and South Dakota, respectively.

 

***Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms*** — NSP-Minnesota’s retail electric rateschedules in Minnesota, North Dakota and South Dakota jurisdictions include anFCA that provides for monthly adjustments to billings and revenues for changesin prudently incurred cost of fuel, fuel related items and purchasedenergy.  NSP-Minnesota is permitted torecover these costs through FCA mechanisms individually approved by theregulators in each jurisdiction.  The FCAmechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuelrelated costs used to generate electricity at its plants and energy purchasedfrom other suppliers.  In general,capacity costs are not recovered through the FCA.  NSP-Minnesota’s electric wholesale customersalso have a FCA provision in their contracts.

 

The MPUC has opened aninvestigation to consider the continuing usefulness of fuel clause adjustmentsfor electric utilities in Minnesota.  Noaction has been proposed.  The MPUC hasthe authority to disallow recovery of certain costs if it finds the utility wasnot prudent in its procurement activities.

 

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

 

***Performance-Based Regulation and Quality of Service Requirements***— In December 2003, the MPUC voted toapprove NSP-Minnesota’s MERP proposal to convert two coal-fueled electricgenerating plants to natural gas, and to install advanced pollution controlequipment at a third coal-fired plant. All three plants are located in the Minneapolis - St. Paul metropolitanarea. These

 

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improvements are expected tosignificantly reduce air emissions from these facilities, while increasing thecapacity at system peak by 300 MW. The projects are expected to come on linebetween 2007 and 2009, at a cumulative investment of approximately $1billion.  The MPUC also approvedNSP-Minnesota’s proposal to recover prudent costs of the projects through arate adjustment provision applicable to retail electric rates beginning Jan. 1,2006, including a rate of return on the construction work in progress.  The MPUC approval has a sliding ROE scalebased on actual construction cost compared with a target level of constructioncosts (based on an equity ratio of 48.5 percent and debt of 51.5 percent) toincentivize NSP-Minnesota to control construction costs.

 

| **Actual Costs as a Percent of Target Costs** | ** ** | **ROE**    | ** ** |
|-----------------------------------------------|------------|------------|------------|
| ** **                                    | ** ** | ** ** | ** ** |
| Less than or  equal to 75%                    |       | 11.47      | %          |
| Over 75% and  up through 85%                  |       | 11.22      | %          |
| Over 85% and  up through 95%                  |       | 11.00      | %          |
| Over 95% and  up through 105%                 |       | 10.86      | %          |
| Over 105%  and up through 115%                |       | 10.55      | %          |
| Over 115%  and up through 125%                |       | 10.22      | %          |
| Over 125%                                     |       | 9.97       | %          |

*** ***

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

*** ***

*MISOOperations**—***In August 2000, NSP-Minnesota andNSP-Wisconsin joined the MISO.  In December 2001,the FERC approved the MISO as the first RTO in the United States under FERCOrder No. 2000. On Feb. 1, 2002, the MISO began interim operations, includingregional transmission tariff administration services for the NSP-Minnesota andNSP-Wisconsin electric transmission systems. In 2002, NSP-Minnesota andNSP-Wisconsin received all required regulatory approvals to transfer functionalcontrol of their high voltage (100 KV and above) transmission systems to theMISO. The MISO membership grants MISO functional control over the operations ofthese facilities and the facilities of certain neighboring electric utilities.

 

On March 31,2004, the MISO filed its proposed TEMT, which would establish regional wholesaleenergy markets using locational marginal cost pricing and FTRs.  NSP-Minnesota and NSP-Wisconsin’s generationplants and transmission systems would operate subject to the TEMT.  The MISO proposed a Dec. 1, 2004 effectivedate.

 

On May 26, 2004, the FERCissued an initial procedural order.  TheFERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) fortransmission service could negatively affect implementation of the TEMT, soFERC delayed the effective date of the energy market to March 1,2005.  NSP-Minnesota and NSP-Wisconsinsubmitted compliance filings regarding their approximately 50 GFAs on June 25,2004.  Approximately 10 GFAs weredisputed, and hearings were held June 30, 2004 and July 1, 2004.  The other GFAs are not disputed.  The primary disputed issues related toresponsibility for TEMT charges for loads served under the GFAs.  On Sept. 16, 2004, the FERC issued an orderruling that certain GFAs would be “carved out” of the MISO market but thattransmission owners would be subject to the TEMT charges for other GFAs.  The FERC has not issued a final decision onrehearing.  On Jan. 13, 2005, severaltransmission-owning members of the MISO, including NSP-Minnesota, filedrevisions to the MISO tariff to recover TEMT charges from the customers subjectto the “carved out” GFAs, effective March 1, 2005.  NSP-Minnesota and NSP-Wisconsin expect tofile for rate changes under certain GFAs to recover TEMT charges from these GFAcustomers later in 2005.

 

On Aug. 6, 2004, aftercompletion of the GFA hearings and submission of the ALJ report, the FERCissued its initial substantive order regarding the TEMT.  The FERC approved the TEMT and reaffirmed theMarch 1, 2005 effective date, but ordered various changes to the filedtariff.  On Sept. 7, 2004, numerousrequests for rehearing were filed contesting various FERC decisions.  On Nov. 8, 2004, the FERC issued its order onrehearing largely upholding the August 6th order.  On or before Jan. 6, 2005, several appeals ofthe two FERC orders were filed with the District of Columbia Court ofAppeals.  NSP-Minnesota does not believethe outcome of the appeals will have a material financial impact.  In addition, various parties, includingNSP-Minnesota, have documented their concerns to MISO regarding MISO’sreadiness to initiate the new energy market on March 1, 2005.  On Jan. 27, 2005, MISO announced a delay inthe full market start date until April 1, 2005.

 

NSP-Minnesota opposescertain aspects of the TEMT-related implementation practices as presentlydesigned, and believes the MISO should implement the new market mechanisms onlyafter it demonstrates that it has fully developed all operating proceduresnecessary to protect reliability. NSP-Minnesota cannot at this time estimate the total financial impact ofthe new market structure.  NSP-Minnesotaalso cannot predict at this time whether the numerous remaining issues will beresolved in time to allow the MISO market to commence on the new April 1,2005 start date, as proposed.

 

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*WisconsinPublic Service Corp. vs. MISO*— On Dec. 27, 2004, Wisconsin Public Service Corp. (WPS) filed acomplaint with the FERC alleging that certain FTRs allocated to NSP-Minnesotain MISO’s FTR nomination and allocation process, associated with theimplementation of the new MISO TEMT, improperly granted NSP-Minnesota FTRs tothe detriment of WPS.  WPS alleged theFTR allocation to NSP-Minnesota would increase costs to WPS and its customers.  WPS requested accelerated processing of thecomplaint.  On Jan. 15, 2005, MISO andNSP-Minnesota filed answers asking that the WPS complaint be dismissed.  The complaint is now pending resolution bythe FERC.  In a related matter, WPSappealed to the U.S. District Court for the District of Columbia previous FERCorders upholding NSP-Minnesota’s right to the underlying transmission serviceat issue in the MISO FTR allocation.  Theappeal is scheduled to be heard by the court in April 2005.

 

*MISO LongTerm Pricing**—***On Nov. 18, 2004, FERC issued an orderapproving portions of a plan providing for continued use of “license plate”rates for the MISO/PJM region, but rejecting proposed transition payments.  FERC instead ordered the MISO and PJM to filea Seams Elimination Charge Adjustment (SECA) transition mechanism.  The replacement compliance filings weresubmitted Nov. 24, 2004, to be effective December 1, 2004.  The FERC order eliminates any transitionpayments and the SECA filings instead provide for both revenues and paymentsthat net to approximately $117,000 in revenues per month to NSP-Minnesota andNSP-Wisconsin in the first three months of 2005.  MISO and PJM are required to update the SECAcharges effective April 1, 2005. The magnitude of the new charges and payments is unknown at this time,but is expected to be similar to the charges and payments for the first threemonths of 2005.

 

Various parties soughtrehearing of the Nov. 18, 2004 order and/or filed objections to the Nov. 24,2004 SECA compliance filings.  On Feb.10, 2005, the FERC issued an order accepting the SECA filings effective Dec. 1,2004, subject to refund, and set the proposals for hearings.  Therefore, the final resolution of the SECAissue and its impact on NSP-Minnesota and NSP-Wisconsin, is not fully known atthis time.

 

*InterchangeAgreement*— On Jan.26, 2005, NSP-Minnesota and NSP-Wisconsin filed the annual revisions to theinterchange agreement, a FERC rate schedule that shares the costs of theintegrated generation and transmission systems of the two utilities.  In addition to updating the cost allocationfactors to reflect changes to their respective customer loads, NSP-Minnesotaand NSP-Wisconsin filed a revised loss study that will affect the allocation ofthe costs of electrical losses to be effective Jan. 1, 2005.  The updated loss study utilizes the samemethodology previously approved by the FERC. The updated cost allocation factors, which include the updated lossratios calculated in the study, are expected to decrease the actual costsallocated to NSP-Minnesota by approximately $11 million per year.

 

***Pending and RecentlyConcluded Regulatory Proceedings***- MPUC

*** ***

*Minnesota Service Quality Investigation*— In 2002, the MPUC directed the Office of theAttorney General and the Minnesota Department of Commerce (state agencies) toinvestigate the accuracy of NSP-Minnesota’s electric reliability records, whichare summarized and reported to the MPUC on a monthly and annual basis, subjectto penalty for not meeting threshold requirements, under the terms of themerger settlement agreements.

 

In 2003,NSP-Minnesota and the state agencies announced that they had reached asettlement agreement, which was approved with modifications by the MPUC in January 2004.  The settlement required NSP-Minnesota torefund $1 million to customers in Minnesota, which was paid in 2004.  In addition, it required NSP-Minnesota toincur at least $15 million of costs for actions to improve system reliabilityabove amounts being recovered in 2004 rates by Jan. 1, 2005, for which $19 millionwas expended in 2004.  The MPUC modifiedthe settlement to include an additional under-performance payment for anyfuture finding of inaccurate reliability data.

 

*NRG Tax Complaint **—***InNovember 2003, an NSP-Minnesota customer filed a complaint with the MPUCalleging that ratepayers are entitled to a share of the tax benefitsattributable to NRG. The customer subsequently supplemented this complaint withsufficient signatures from customers to warrant a formal complaint process bythe MPUC. NSP-Minnesota responded to the complaint, arguing that the requestedtreatment is not allowed by law and is inconsistent with the MPUC’s directivesto ensure full separation of NSP-Minnesota and NRG. In August 2004, theMPUC decided not to pursue this complaint. The MPUC affirmed the long-standingprecedent to view each utility as a stand-alone business that does notexperience positive or negative effects from its affiliates.  The customer filed an appeal of this decisionon Jan. 7, 2005, and NSP-Minnesota filed a responsive statement of the case onJan. 18, 2005.  The Attorney General’soffice petitioned to file an advisory brief to the customer’s case.

 

*RenewableTransmission Cost Recovery —*In 2002, NSP-Minnesota filed for MPUC approval to establish an RCRadjustment

 

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mechanism to recover thecosts of transmission investments incurred to deliver renewable energyresources.  The RCR adjustment mechanismprovides for annual filings to set the RCR adjustment rates using updatedtransmission cost information.  The MPUCapproved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003.  In February 2004, the MPUC conditionallyapproved the initial Phase 1 facility eligibility determination filing.  NSP-Minnesota then filed for approval torecover annual additional transmission costs from May 2004 to December 2004,which were approximately $6 million. The request was approved and the RCR wasimplemented Dec. 1, 2004.  NSP-Minnesotacollected approximately $0.2 million in 2004. NSP-Minnesota submitted a filing to determine the eligibility ofadditional transmission projects and to establish the RCR factors for 2005 in February 2005,seeking recovery of $12.9 million of additional revenues in 2005.

 

*Time-of-UsePilot Project —*Asrequired by MPUC orders, NSP-Minnesota has been working to develop atime-of-use pilot project that would attempt to measure customer response andconservation potential of such a program. This pilot project explores providingcustomers with pricing signals and information that could better informcustomers about their use of electricity and its costs. NSP-Minnesota haspetitioned the MPUC for recovery of program costs. The 2002 program costs wereapproximately $2 million. The Department of Commerce has supported deferredaccounting to provide for recovery of prudent, otherwise unrecovered andappropriate costs, subject to a normal prudence review process. The Office ofthe Attorney General has argued that cost recovery should be denied for severalreasons. A MPUC hearing was held in January 2004 and requestedNSP-Minnesota to further substantiate the prudence and appropriateness of thecosts incurred.  The MPUC has voted toallow recovery of the program costs.  Anorder of the MPUC is expected in early 2005.

 

*MISO CostRecovery Petition*—On Dec. 18, 2004, NSP-Minnesota filed a petition to seek recovery of all netcosts associated with the implementation of the MISO TEMT through its FCAmechanism.  Under the current mechanism,NSP-Minnesota is allowed full recovery of its fuel and purchased energycosts.  The proposal would allow recoveryof locational marginal pricing market costs, including congestion and marginalloss costs, which would be netted by FTR revenues and revenues received thatare related to marginal compensation loss costs, as well as MISO energy marketoperations costs.  NSP-Minnesota hassought recovery effective with the beginning of the Day 2 energy market,scheduled for April 1, 2005 and the deferral of costs incurred prior toMPUC action.  A decision is expected inthe second quarter of 2005.

 

**Capacityand Demand**

 

Assuming normal weatherduring 2005, system peak demand for the NSP System’s electric utility for eachof the last three years and the forecast for 2005 is listed below.

 

| ** ** | ** ** | **System Peak Demand (in MW)** | ** ** |
|------------|------------|--------------------------------|------------|
| ** ** | ** ** | **2002**                       | ** ** | **2003** | ** ** | **2004** | ** ** | **2005 Forecast** | ** ** |
| ** ** | ** ** | ** **                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| NSP System |       | 8,259                          |       | 8,289 |   | 8,595 |   | 8,369 |   |

 

The peak demand for the NSPSystem typically occurs in the summer. The 2004 system peak demand for the NSPSystem occurred on July 21, 2004.

 

**Energy Sources and Related Transmission Initiatives**

 

The NSP System expects touse existing electric generating stations; purchases from other utilities,independent power producers and power marketers; demand-side management optionsand phased expansion of existing generation at select power plants to meet itsnet dependable system capacity requirements.

 

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

 

NSP-Minnesota also makesshort-term firm and non-firm purchases to replace generation from company-ownedunits that are unavailable due to maintenance and unplanned outages, to provideeach utility’s reserve obligation, to obtain energy at a lower cost than thatwhich could be produced by other resource options, including company-ownedgeneration and/or long-term purchase power contracts, and for various otheroperating requirements.

 

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***NSP System Resource Plan***— On Nov. 1, 2004, NSP-Minnesota filedthe NSP System 2004 resource plan with MPUC. The resource plan projects a need for an additional 3,100 MW ofelectricity resources during the next 15 years, based on an anticipated growthin demand of 1.61 percent annually, or approximately 170 MW per year, duringthe period.  The resource plan:

 

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

 

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

 

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

 

•                  recommends extending the operating licensesfor the Prairie Island and Monticello nuclear plants by 20 years (on Jan. 18,2005, NSP-Minnesota applied for a certificate of need in Minnesota for a dryspent-fuel storage facility at the Monticello plant, and plans to file anapplication with the federal government to extend the Monticello plant’slicense and to make similar filings for the Prairie Island plant in 2008);

 

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

 

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

 

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

 

The MPUC initiallyestablished a comment period on NSP-Minnesota’s proposed resource acquisitionstrategy with comments due Dec. 28, 2004 and reply comments due Jan. 17,2005.  The Department of Commerce hasrequested an extension to June 1, 2005 to file comments on the overallresource plan.  NSP-Minnesota did notobject to this request.

 

***NSP-Minnesota Transmission Certificates of Need***— In December 2001, NSP-Minnesotaproposed construction of various transmission system upgrades to providetransmission outlet capacity for up to 825 MW of renewable energy generation(wind and biomass) being constructed in southwest and western Minnesota. In March 2003,the MPUC granted four certificates of need to NSP-Minnesota, thereby approvingconstruction, subject to certain conditions. The initial projected cost of thetransmission upgrades was approximately $160 million.  The MEQB granted a routing permit for thefirst major transmission facilities in the development program in 2004.  The remaining route permit proceedings areunderway and expected to be completed in 2005. In 2003, the MPUC also approved a RCR adjustment that allowsNSP-Minnesota to recover the revenue requirements associated with certaintransmission investments associated with delivery of renewable energy resourcesthrough an automatic adjustment mechanism that started in 2004.  See the Pending and Recently ConcludedRegulatory Proceedings – MPUC, Renewable Transmission Cost Recovery section forfurther discussion.

 

***Purchased Transmission Services***— NSP-Minnesota and NSP-Wisconsin havecontractual arrangements with MISO to deliver power and energy to NSP Systemnative load customers, which are retail and wholesale load obligations withterms of more than one year.  Point-to-pointtransmission services typically include a charge for the specific amount oftransmission capacity being reserved, although some agreements may base chargeson the amount of metered energy delivered. Network transmission servicesinclude a charge for the metered demand at the delivery point at the time ofthe provider’s monthly transmission system peak, usually calculated as a12-month rolling average.

 

###### ***Nuclear Power Operationsand Waste Disposal -***NSP-Minnesota owns two nuclear generating plants: theMonticello plant and the Prairie Island plant. See additional discussionregarding the nuclear generating plants at Note 12 to the ConsolidatedFinancial Statements.

###### *** ***

Nuclear power plantoperation produces gaseous, liquid and solid radioactive substances. Thedischarge and handling of such substances are controlled by federalregulation.  High-level radioactivesubstances primarily include used nuclear fuel. Low-level radioactive substanceconsists primarily of demineralizer resins, paper, protective clothing, rags,tools and equipment that have become contaminated through use in the plant.

 

*Low-LevelRadioactive Waste Disposal**—***Federal law places responsibility on eachstate for disposal of its low-level radioactive substance. Low-levelradioactive substance from NSP-Minnesota’s Monticello and Prairie Islandnuclear plants is currently disposed of at the Barnwell facility located inSouth Carolina (all classes of low-level substance), and the Clive facilitylocated in Utah (class A low-level substance only). Chem Nuclear is the ownerand operator of the Barnwell facility, which has been given authorization bySouth Carolina to accept low-level radioactive substance from out of state.Envirocare, Inc. operates the Clive facility. NSP-Minnesota has an annualcontract with Barnwell, while NSP-Minnesota uses the Envirocare facilitythrough various low-level substance

 

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processors. NSP-Minnesotahas low-level storage capacity available on-site at Prairie Island andMonticello that would allow both plants to continue to operate until the end oftheir licensed lives, if off-site low-level disposal facilities were notavailable to NSP-Minnesota.

 

*High-LevelRadioactive Waste Disposal**—***The federal government has the responsibilityto dispose of, or permanently store, domestic spent nuclear fuel and otherhigh-level radioactive substances. The Nuclear Waste Policy Act requires theDOE to implement a program for nuclear substance management. This includes thesiting, licensing, construction and operation of a repository for domesticallyproduced spent nuclear fuel from civilian nuclear power reactors and otherhigh-level radioactive substances at a permanent storage or disposal facility.The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel. See Item 3 —Legal Proceedings and Note 12 to the Consolidated Financial Statements forfurther discussion of this matter.  TheNational Commission on Energy Policy, a privately funded coalition, hasrecommended that the federal government continue to pursue a nuclear wastestorage facility in Nevada’s Yucca Mountain and urged them to build multipleabove ground dry cask storage sites in the eastern and western United States incase the Yucca Mountain project is delayed or cancelled.

 

NSP-Minnesota has on-sitestorage for spent nuclear fuel at its Monticello and Prairie Island nuclearplants. The Prairie Island plant is licensed by the federal NRC to store up to48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopteda limit on dry cask storage of 17 casks for the entire state. The 17 casks,which stand outside the Prairie Island plant, are now full. On May 29, 2003,the Minnesota Legislature enacted legislation that allows NSP-Minnesota tocontinue to operate the facility and store spent fuel there until its licenseswith NRC expire in 2013 and 2014. This will enable NSP-Minnesota to store atleast 12 more casks of spent fuel outside the Prairie Island nuclear generatingplant. The legislation transfers the primary authority concerning future spent-fuelstorage issues from the state Legislature to the MPUC. It also allows foradditional storage without the requirement of an affirmative vote from thestate Legislature, if the NRC extends the licenses of the Prairie Island andMonticello plants and the MPUC grants a certificate of need for such additionalstorage. See Note 12 in the Consolidated Financial Statements for furtherdiscussion of the matter.

 

*VisualInspections**—***Required visual inspections have beenperformed on the Prairie Island Unit 2 upper and lower reactor vessel heads,and the Unit 1 upper head.  Reactorvessel heads for both units were found to be in compliance with all NRCrequirements. Xcel Energy has placed orders and plans to replace the reactorvessel upper heads of Prairie Island Unit 2 during the 2005 refueling outageand Unit 1 during the 2006 refueling outage.

 

*PrivateFuel Storage**—***NSP-Minnesota is part of a consortium ofprivate parties working to establish a private facility for interim storage ofspent nuclear fuel. In 1997, PFS filed a license application with the NRC for atemporary storage site for spent nuclear fuel on the Skull Valley IndianReservation in Utah. The NRC license review process includes formal evidentiaryhearings before an ASLB and opportunities for public input. Evidentiaryhearings were held in 2000 and 2002.  In December 2004,the state of Utah claimed a representative of the DOE stated that it would notaccept waste sealed in the type of containers planned by PFS.  PFS responded by providing documents that theDOE will accept fuel stored in dry casks. The ASLB ruled in February 2005 that it would not reopen the hearing recordto consider this issue, indicating it was instead worthy of NRCconsideration.  The ASLB also issued itsdecision on the last remaining issue regarding the facility, finding in favorof PFS. NRC commissioners will decide whether to officially issue a license forthe site.  The state of Utah has askedthe U.S. Supreme Court to consider whether the state of Utah can block PFS fromlocating a spent fuel storage facility in the state, if the federal governmenthas exclusive control over the storage and transportation of nuclearwaste.  The court neither accepted nordeclined the appeal filed by the state of Utah, but has sought additionalinformation.  Due to uncertaintyregarding NRC and other regulatory and governmental approvals, it is possiblethat this interim storage may be delayed or not available at all.

 

*PrairieIsland Steam Generator Replacement**—***In the fall of 2004, NSP-Minnesota spentapproximately $132 million to successfully replace the steam generators at Unit1 of the Prairie Island nuclear generating plant.  The steam generators at Unit 2 have not yetbeen replaced, but will be inspected during a scheduled 2005 outage.

 

*NSP-Minnesota Nuclear Plant Re-licensing* — On Aug. 25, 2004, the Xcel Energyboard of directors authorized the pursuit of renewal of the operating licensesfor the Monticello and Prairie Island nuclear plants. Monticello’s current40-year license expires in 2010, and Prairie Island’s licenses for its twounits expire in 2013 and 2014. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005seeking a certificate of need for dry spent fuel storage and plans to file anapplication in 2005 with the NRC for an operating license extension of up to 20years.  A decision regarding Monticellore-licensing is expected in 2007. Plant assessments and other work for thePrairie Island applications are planned in the next two or three years.

 

*NuclearManagement Co. (NMC)*****— During 1999, NSP-Minnesota,Wisconsin Electric Power Co., WPS and Alliant Energy Corp. established NMC. Theobjective in creating NMC was to enhance operational excellence in nuclear plantoperations by consolidating

 

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resources,combining talent and gaining efficiencies. The Consumers Power subsidiary ofCMS Energy Corp. joined NMC during 2000, and transferred operating authorityfor the Palisades nuclear plant to NMC in 2001. The five affiliated companiesown eight nuclear units on six sites, with total generation capacity exceeding4,500 MW. WPS is seeking regulatory approval to sell its Kewaunee Nuclear PowerPlant to a subsidiary of Dominion Resources, Inc., and may not continue toparticipate in NMC.  In addition, AlliantEnergy has announced that it intends to seek bids to potentially sell the DuaneArnold nuclear plant and, therefore, may not continue to participate in theNMC.

 

The NRC has approvedrequests by NMC’s affiliated utilities to transfer operating authority fortheir nuclear plants to NMC, formally establishing NMC as an operating company.NMC manages the operations and maintenance at the plants, and is responsiblefor physical security. NMC’s responsibilities also include oversight of on-sitedry storage facilities for used nuclear fuel at the Prairie Island nuclearplant. Utility plant owners, including NSP-Minnesota, continue to own theplants, control all energy produced by the plants, and retain responsibilityfor nuclear liability insurance and decommissioning costs. Existing personnelcontinue to provide day-to-day plant operations, with the additional benefit ofimplementing best practices from all NMC-operated plants for improved safety,reliability and operational performance.

 

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

 

**Fuel Supplyand Costs**

 

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

 

| ** ** | ** ** | **Coal***  | ** ** | **Nuclear** | ** ** | **Average Fuel** | ** ** |
|------------|------------|------------|------------|-------------|------------|------------------|------------|
| ** ** | ** ** | ** ** | ** ** | ** **  | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** ** | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Cost**         | ** ** | **Percent** | ** ** | **Cost** | ** ** |
| ** ** | ** ** | ** ** | ** ** | ** **  | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** |
| 2004       |       | $          | 0.99       |        | 61         | %                | $          | 0.44 |   | 37 | % | $ | 0.92 |   |
| 2003       |       | $          | 0.99       |        | 61         | %                | $          | 0.43 |   | 36 | % | $ | 0.90 |   |
| 2002       |       | $          | 0.96       |        | 59         | %                | $          | 0.46 |   | 38 | % | $ | 0.81 |   |

 

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* Includes refuse-derivedfuel and wood

 

***Fuel Sources***— The NSP System normally maintains between 30 and 50 days of coalinventory at each plant site. Estimated coal requirements at NSP-Minnesota’smajor coal-fired generating plants are approximately 12.7 million tons peryear. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing forthe delivery of up to 97 percent of 2005 coal requirements and up to 59 percentof the 2006 requirements. Coal delivery may be subject to short-terminterruptions or reductions due to transportation problems, weather, andavailability of equipment.

 

NSP-Minnesota andNSP-Wisconsin expect that all of the coal burned in 2005 will have an averagesulfur content of less than 0.5 percent. The NSP System has contracts for amaximum of 22.9 million tons of low-sulfur coal for the next 3 years. Thecontracts are with 1 Montana coal supplier, 3 Wyoming suppliers and 1 Minnesotaoil refinery, with expiration dates ranging between 2006 and 2007.  The NSP System could purchase approximately20 percent of coal requirements in the spot market in 2006 if spot prices aremore favorable than contracted prices.

 

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

 

•                    Current nuclear fuel supply contracts cover46 percent of uranium requirements through 2006 with no coverage ofrequirements for 2007 and beyond.

 

•                    Current contracts for conversion servicesrequirements cover 32 percent of the requirements through 2007 with no coverageof requirements for 2008 and beyond.

 

•                    Current enrichment services contracts cover55 percent of the requirements through 2010 with no coverage of requirementsfor 2011 and beyond. These current contracts expire at varying times between2005 and 2010.

 

•                    Fuel fabrication for Monticello is coveredthrough 2010.  Fuel fabrication is 100percent committed for Prairie Island Unit 1 through 2006 and through 2005 forPrairie Island Unit 2.  Both PrairieIsland Units are not contracted for fuel fabrication beyond those dates.  NSP-Minnesota and NMC are currently innegotiations with Westinghouse to pursue fuel fabrication for

 

15

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PrairieIsland plant needs beyond the current fuel contracts.

 

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

 

TheNSP System uses both firm and interruptible natural gas and standby oil incombustion turbines and certain boilers. Natural gas supplies for power plantsare procured under short- and intermediate-term contracts to provide anadequate supply of fuel.  The NSP Systemhas current fuel oil inventory adequate to meet anticipated 2005 requirementsand also has access to the spot market to buy more oil, if needed.

 

**CommodityMarketing Operations**

 

NSP-Minnesota conductsvarious wholesale marketing operations, including the purchase and sale ofelectric capacity, energy and energy related products. Participation inshort-term wholesale energy markets provides market intelligence andinformation that supports the energy management of NSP-Minnesota.  NSP-Minnesota uses physical and financialinstruments to minimize commodity price and credit risk and hedge supplies andpurchases. Engaging in short-term sales and purchase commitments results in anefficient use of our plants and the capturing of additional margins fromnon-traditional customers. NSP-Minnesota also uses these marketing operationsto capture arbitrage opportunities created by regional pricing differentials,supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A —Quantitative and Qualitative Disclosures About Market Risk.

 

16

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## **NSP-MinnesotaElectric Operating Statistics**

 
| ** **                                 | ** ** | **Year Ended Dec. 31,** | ** ** |
|--------------------------------------------|------------|-------------------------|------------|
| ** **                                 | ** ** | **2004**                | ** ** | **2003** | ** ** | **2002** | ** ** |
| Electric  Sales (Millions of Kwh):         |       |                    |       |   |   |   |   |
| Residential                                |       | 9,558                   |       | 9,778 |   | 9,782 |   |
| Commercial  and industrial                 |       | 24,323                  |       | 24,087 |   | 23,818 |   |
| Public  authorities and other              |       | 284                     |       | 281 |   | 274 |   |
| Total retail                               |       | 34,165                  |       | 34,146 |   | 33,874 |   |
| Sales for  resale                          |       | 4,635                   |       | 4,750 |   | 4,945 |   |
| Total energy  sold                         |       | 38,800                  |       | 38,896 |   | 38,819 |   |
|                                       |       |                    |       |   |   |   |   |
| Number of  customers at end of period:     |       |                    |       |   |   |   |   |
| Residential                                |       | 1,201,560               |       | 1,180,558 |   | 1,165,237 |   |
| Commercial  and industrial                 |       | 144,631                 |       | 141,584 |   | 139,779 |   |
| Public  authorities and other              |       | 5,984                   |       | 5,496 |   | 5,740 |   |
| Total retail                               |       | 1,352,175               |       | 1,327,638 |   | 1,310,756 |   |
| Wholesale                                  |       | 69                      |       | 59 |   | 58 |   |
| Total  customers                           |       | 1,352,244               |       | 1,327,697 |   | 1,310,814 |   |
|                                       |       |                    |       |   |   |   |   |
| Electric  revenues (Thousands of dollars): |       |                    |       |   |   |   |   |
| Residential                                |       | $                       | 757,748    |   | $ | 753,661 |   | $ | 736,485 |   |
| Commercial  and industrial                 |       | 1,324,773               |       | 1,267,470 |   | 1,204,371 |   |
| Public  authorities and other              |       | 31,965                  |       | 31,427 |   | 30,442 |   |
| Regulatory  accrual adjustment             |       | —                  |       | — |   | 4,766 |   |
| Total retail                               |       | 2,114,486               |       | 2,052,558 |   | 1,976,064 |   |
| Wholesale                                  |       | 168,317                 |       | 148,087 |   | 109,147 |   |
| Sales to  NSP-Wisconsin                    |       | 220,165                 |       | 227,946 |   | 219,006 |   |
| Other  electric revenues                   |       | 82,388                  |       | 57,151 |   | 58,455 |   |
| Total  electric revenues                   |       | $                       | 2,585,356  |   | $ | 2,485,742 |   | $ | 2,362,672 |   |
|                                       |       |                    |       |   |   |   |   |
| Kwh sales  per retail customer             |       | 25,267                  |       | 25,719 |   | 25,843 |   |
| Revenue per  retail customer               |       | $                       | 1,563.77   |   | $ | 1,546.02 |   | $ | 1,507.58 |   |
| Residential  revenue per Kwh               |       | 7.93                    | ¢     | 7.71 | ¢ | 7.53 | ¢ |
| Commercial  and industrial revenue per Kwh |       | 5.45                    | ¢     | 5.26 | ¢ | 5.06 | ¢ |
| Wholesale  revenue per Kwh                 |       | 3.63                    | ¢     | 3.12 | ¢ | 2.21 | ¢ |

 

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**NATURAL GAS UTILITY OPERATIONS**

 

# **Summaryof Recent Regulatory Developments**

 

Changesin regulatory policies and market forces have shifted the industry fromtraditional bundled natural gas sales service to an unbundled transportationand market-based commodity service at the wholesale level and for largercommercial and industrial retail customers. These customers have greaterability to buy natural gas directly from suppliers and arrange their ownpipeline and retail LDC transportation service.

 

Thenatural gas delivery and transportation business has remained competitive asindustrial and large commercial customers have the ability to bypass the localnatural gas utility through the construction of interconnections directly withinterstate pipelines, thereby avoiding the delivery charges added by the localnatural gas utility.

 

As anLDC, NSP-Minnesota provides unbundled transportation service to largecustomers. Transportation service does not have an adverse effect on earningsbecause the sales and transportation rates have been designed to make themeconomically indifferent to whether natural gas has been sold and transportedor merely transported. However, some transportation customers may have greateropportunities or incentives to physically bypass the LDCs distribution system.

 

The most significant recentdevelopments in the natural gas operations of the Utility Subsidiaries are thesubstantial and continuing increases in wholesale natural gas market prices andthe continued trend toward declining use per customer by residential customersas a result of improved building construction technologies and higher applianceefficiencies.  From 1994 to 2004, averageannual sales to the typical residential customer declined from 111 Dth per yearto 99 Dth per year on a weather-normalized basis.  Although recent wholesale price increases donot directly affect earnings because of gas cost recovery mechanisms, the highprices are expected to encourage further efficiency efforts by customers.

 

**RatemakingPrinciples**

 

***Summary of Regulatory Agencies and Areas ofJurisdiction***— Retail rates, services and other aspectsof NSP-Minnesota’s operations are subject to the jurisdiction of the MPUC andthe NDPSC within their respective states. The MPUC has regulatory authorityover aspects of NSP-Minnesota’s financial activities, including securityissuances, certain property transfers, mergers with other utilities andtransactions between NSP-Minnesota and its affiliates. In addition, the MPUCreviews and approves NSP-Minnesota’s gas supply plans for meeting customers’future energy needs.

 

***Purchased Gas and Conservation CostRecovery Mechanisms***—****NSP-Minnesota’sretail natural gas rate schedules for Minnesota and North Dakota include a PGAclause that provides for prospective monthly rate adjustments to reflect theforecasted cost of purchased natural gas. The annual difference between thenatural gas costs collected through PGA rates and the actual natural gas costsare collected or refunded over the subsequent 12-month period. The MPUC has theauthority to disallow recovery of certain costs if it finds the utility was notprudent in its procurement activities.

 

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

 

***Pending and Recently Concluded RegulatoryProceedings***

 

*NSP-Minnesota Retail Gas Rate Case* - OnSept. 17, 2004, NSP-Minnesota submitted a $10 million natural gas general rateincrease request to the MPUC with a requested return on equity of 11.5percent.  An interim rate increase,subject to refund, of approximately $6.4 million was implemented effective Dec.1, 2004.  The ALJ held a pre-hearingconference and established a procedural schedule, with an MPUC decisionexpected in mid-2005.  The Department ofCommerce filed testimony in February 2005 recommending an increase of $1million.  NSP-Minnesota plans to file itsrebuttal testimony on March 15, 2005.

 

*North Dakota Retail Gas Rate Case* — On Nov. 2, 2004, NSP-Minnesota submitted a natural gas general rate increase application to the NDPSC.  The filing proposes an overall increase in annual revenues of $1.3 million, exclusive of natural gas supply costs, or 1.8 percent.  On Dec. 1, 2004, the NDPSC issued an order approving a $0.7 million interim rate increase, or 1.1 percent, effective Jan. 1, 2005.  The NDPSC staff is scheduled to file its testimony in March 2005, and the NDPSC will conduct evidentiary hearings in April 2005.  The NDPSC is required to issue its order by June 2, 2005.  On Feb. 17, 2005, however, NSP-Minnesota and the NDPSC staff filed a settlement agreement with the NDPSC.  Under the terms of the settlement, the NDPSC can elect one of two alternatives.  The alternatives are a $745,000 rate increase and a $15.70 monthly residential service charge or an $887,000 rate increase with an $8.75

 

18

 

monthly residential service charge.  The NDPSC is expected to consider the settlement agreement at a hearing in March 2005.

 

**Capabilityand Demand**

 

Naturalgas supply requirements are categorized as firm or interruptible (customerswith an alternate energy supply). The maximum daily send-out (firm andinterruptible) for NSP-Minnesota was 647,547 MMBtu for 2004, which occurred onJan. 29, 2004.

 

NSP-Minnesotapurchases natural gas from independent suppliers. The natural gas is deliveredunder natural gas transportation agreements with interstate pipelines. Theseagreements provide for firm deliverable pipeline capacity of approximately506,391 MMBtu/day. In addition, NSP-Minnesota has contracted with providers ofunderground natural gas storage services. These storage agreements providestorage for approximately 16 percent of winter natural gas requirements and 19percent of peak day, firm requirements of NSP-Minnesota.

 

NSP-Minnesotaalso owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalentand three propane-air plants with a storage capacity of 1.4 Bcf equivalent tohelp meet its peak requirements. These peak-shaving facilities have productioncapacity equivalent to 250,300 MMBtu of natural gas per day, or approximately34 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-Minnesotais required to file for a change in natural gas supply contract levels to meetpeak demand, to redistribute demand costs among classes or to exchange one formof demand for another. NSP-Minnesota’s 2003-2004 entitlement levels wereapproved on Sept. 2, 2004, which allow NSP-Minnesota to recover the demandentitlement costs associated with the increase in transportation, supply, andstorage levels in its monthly PGA. The 2004-2005 entitlement levels are pendingMPUC action.

 

**NaturalGas Supply and Costs**

 

NSP-Minnesotaactively seeks natural gas supply, transportation and storage alternatives toyield a diversified portfolio that provides increased flexibility, decreasedinterruption and financial risk, and economical rates. This diversificationinvolves numerous domestic and Canadian supply sources with varied contractlengths.

 

Thefollowing table summarizes the average cost per MMBtu of natural gas purchasedfor resale by NSP-Minnesota’s regulated retail natural gas distributionbusiness:

 

| 2004 |   | $ | 6.88 |   |
|------|--------|---|------|--------|
| 2003 |   | $ | 5.47 |   |
| 2002 |   | $ | 3.98 |   |

 

Thecost of natural gas supply, transportation service and storage service isrecovered through various cost recovery adjustment mechanisms.

 

NSP-Minnesotahas firm natural gas transportation contracts with several pipelines, whichexpire in various years from 2005 through 2017.

 

NSP-Minnesotahas certain natural gas supply and transportation agreements that includeobligations for the purchase and/or delivery of specified volumes of naturalgas or to make payments in lieu of delivery. At Dec. 31, 2004, NSP-Minnesotawas committed to approximately $1.09 billion in such obligations under thesecontracts.

 

NSP-Minnesotapurchases firm natural gas supply utilizing long-term and short-term agreementsfrom approximately 35 domestic and Canadian suppliers. This diversity ofsuppliers and contract lengths allows NSP-Minnesota to maintain competitionfrom suppliers and minimize supply costs.

 

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**NSP-MinnesotaNatural Gas Operating Statistics**

 
| ** **                                    | ** ** | **Year Ended Dec. 31,** | ** ** |
|-----------------------------------------------|------------|-------------------------|------------|
| ** **                                    | ** ** | **2004**                | ** ** | **2003** | ** ** | **2002** | ** ** |
| Natural gas  deliveries (Thousands of Dth):   |       |                    |       |   |   |   |   |
| Residential                                   |       | 39,168                  |       | 40,608 |   | 38,407 |   |
| Commercial  and industrial                    |       | 39,186                  |       | 40,597 |   | 38,320 |   |
| Other                                         |       | 1,334                   |       | 1,674 |   | 1,286 |   |
| Total retail                                  |       | 79,688                  |       | 82,879 |   | 78,013 |   |
| Transportation  and other                     |       | 7,727                   |       | 6,477 |   | 8,559 |   |
| Total  deliveries                             |       | 87,415                  |       | 89,356 |   | 86,572 |   |
|                                          |       |                    |       |   |   |   |   |
| Number of  customers at end of period:        |       |                    |       |   |   |   |   |
| Residential                                   |       | 414,782                 |       | 402,893 |   | 393,538 |   |
| Commercial  and industrial                    |       | 39,190                  |       | 38,078 |   | 37,445 |   |
| Total retail                                  |       | 453,972                 |       | 440,971 |   | 430,983 |   |
| Transportation  and other                     |       | 10                      |       | 10 |   | 42 |   |
| Total  customers                              |       | 453,982                 |       | 440,981 |   | 431,025 |   |
|                                          |       |                    |       |   |   |   |   |
| Natural gas  revenues (Thousands of dollars): |       |                    |       |   |   |   |   |
| Residential                                   |       | $                       | 376,676    |   | $ | 360,410 |   | $ | 263,178 |   |
| Commercial  and industrial                    |       | 307,730                 |       | 291,467 |   | 199,196 |   |
| Other                                         |       | —                  |       | — |   | 1 |   |
| Total retail                                  |       | 684,406                 |       | 651,877 |   | 462,375 |   |
| Transportation  and other                     |       | 30,665                  |       | 22,653 |   | 27,197 |   |
| Total gas  revenues                           |       | $                       | 715,071    |   | $ | 674,530 |   | $ | 489,572 |   |
|                                          |       |                    |       |   |   |   |   |
| Dth sales per  retail customer                |       | 175.54                  |       | 187.95 |   | 181.01 |   |
| Revenue per  retail customer                  |       | $                       | 1,507.60   |   | $ | 1,478.28 |   | $ | 1,072.84 |   |
| Residential  revenue per Dth                  |       | $                       | 9.62       |   | $ | 8.88 |   | $ | 6.85 |   |
| Commercial  and industrial revenue per Dth    |       | $                       | 7.85       |   | $ | 7.18 |   | $ | 5.20 |   |
| Transportation  and other revenue per Dth     |       | $                       | 3.97       |   | $ | 3.50 |   | $ | 3.18 |   |

 

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**ENVIRONMENTALMATTERS**

 

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

 

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

 

***Notice of Violation****—*OnDec. 10, 2001, the Minnesota Pollution Control Agency (MPCA) issued a notice ofviolation to NSP-Minnesota alleging air quality violations related to thereplacement of a coal conveyor and violations of an opacity limitation at theA.S. King generating plant.  On April 22,2004, the MPCA executed an agreement with NSP-Minnesota to resolve the allegedair quality violations at the A.S. King generating plant and address allegedair quality reporting violations at the Red Wing and Wilmarth generatingplants.  Conditions of the agreement werefor NSP-Minnesota to pay an $80,000 civil penalty and to complete correctiveactions at the A.S. King, Red Wing and Wilmarth generating plants.  In 2004, NSP-Minnesota paid the civil penaltyand completed all required corrective actions. On Dec. 15, 2004, the MPCA issued a letter acknowledging receipt of thecivil penalty payment and completion of all requirements in the agreement.

 

# **EMPLOYEES**

# ** **

The number of full-timeNSP-Minnesota employees on Dec. 31, 2004 was 2,843. Of these full-timeemployees, 2,197, or 77 percent, are covered under collective bargainingagreements.  NSP-Minnesota full-timeemployees include 395 employees loaned to the NMC.  In addition, the NMC has 778 full-timeemployees of its own.  See Note 7 to theConsolidated Financial Statements for further discussion.  Xcel Energy Services Inc., a subsidiary ofXcel Energy, employees provide services to NSP-MN.

 

**Item 2 —Properties**

 

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

 

Electric utility generatingstations:

 

| **Station, City and  Unit**     | ** ** | **Fuel**         | ** ** | **Installed** | ** ** | **Summer 2004  Net Dependable  Capability (MW)** | ** ** |
|---------------------------------|------------|------------------|------------|---------------|------------|--------------------------------------------------|------------|
| ***Steam:***                    |       |             |       |          |       |                                             |       |
| Sherburne —  Becker, Minn. |       |             |       |          |       |                                             |       |
| Unit 1                          |       | Coal             |       | 1976          |       | 697                                              |       |
| Unit 2                          |       | Coal             |       | 1977          |       | 682                                              |       |
| Unit 3(a)                       |       | Coal             |       | 1987          |       | 504                                              |       |
| Prairie  Island — Welch,   |       |             |       |          |       |                                             |       |
| Minn.                           |       |             |       |          |       |                                             |       |
| Unit 1                          |       | Nuclear          |       | 1973          |       | 523                                              |       |
| Unit 2                          |       | Nuclear          |       | 1974          |       | 522                                              |       |
| Monticello —  Monticello,  |       |             |       |          |       |                                             |       |
| Minn.                           |       | Nuclear          |       | 1971          |       | 572                                              |       |
| King —  Bayport, Minn.     |       | Coal             |       | 1968          |       | 528                                              |       |
| Black Dog —  Burnsville,   |       |             |       |          |       |                                             |       |
| Minn.                           |       |             |       |          |       |                                             |       |
| 2 Units                         |       | Coal/Natural Gas |       | 1955 - 1960   |       | 276                                              |       |
| 2 Units                         |       | Natural Gas      |       | 2002          |       | 298                                              |       |
| High Bridge  — St. Paul,   |       |             |       |          |       |                                             |       |
| Minn.                           |       |             |       |          |       |                                             |       |
| 2 Units                         |       | Coal             |       | 1956 - 1959   |       | 267                                              |       |
| Riverside —  Minneapolis,  |       |             |       |          |       |                                             |       |
| Minn.                           |       |             |       |          |       |                                             |       |
| 2 Units                         |       | Coal             |       | 1964 - 1987   |       | 375                                              |       |
| ***Combustion Turbine:***       |       |             |       |          |       |                                             |       |
| Angus Anson  — Sioux       |       |             |       |          |       |                                             |       |
| Falls, S.D.                     |       |             |       |          |       |                                             |       |
| 2 Units                         |       | Natural Gas      |       | 1994          |       | 226                                              |       |
| Inver Hills  — Inver Grove |       |             |       |          |       |                                             |       |
| Heights,  Minn.                 |       |             |       |          |       |                                             |       |
| 6 Units                         |       | Natural Gas      |       | 1972          |       | 350                                              |       |
| Blue Lake —  Shakopee,     |       |             |       |          |       |                                             |       |
| Minn.                           |       |             |       |          |       |                                             |       |
| 4 Units                         |       | Natural Gas      |       | 1974          |       | 174                                              |       |
| Other                           |       | Various          |       | Various       |       | 261                                              |       |
| Total                           |       |             |       |          |       | 6,255                                            |       |

 

----

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

 

21

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Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) at Dec. 31, 2004:

 
| **Conductor Miles** | ** ** |
|---------------------|------------|
| 500 kilovolt  (KV)  |       | 2,919 |   |
| 345 KV              |       | 5,653 |   |
| 230 KV              |       | 1,442 |   |
| 161 KV              |       | 298 |   |
| 115 KV              |       | 6,278 |   |
| Less than  115 KV   |       | 79,534 |   |

 

NSP-Minnesota had 362electric utility transmission and distribution substations at Dec. 31, 2004.

 

Natural gas utility mains atDec. 31, 2004:

 
| ** **   | ** ** | **Miles** | ** ** |
|--------------|------------|-----------|------------|
| Transmission |       | 115       |       |
| Distribution |       | 8,921     |       |

 

**Item 3 —Legal Proceedings**

 

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

 

***Nuclear Waste Disposal Litigation***—The federal government has the responsibility to dispose of, or permanentlystore, domestic spent nuclear fuel and other high-level radioactive substances.The Nuclear Waste Policy Act requires the DOE to implement a program fornuclear substance management. This includes the siting, licensing, constructionand operation of a repository for domestically produced spent nuclear fuel fromcivilian nuclear power reactors and other high-level radioactive substances ata permanent storage or disposal facility. The federal government has designatedthe site as Yucca Mountain in Nevada. This designation has resulted inextensive litigation.

 

On June 8,1998, NSP-Minnesota filed a complaint in the Court of Federal Claims againstthe DOE requesting damages in excess of $1 billion for the DOE’s partial breachof contract.  NSP-Minnesota has demandeddamages consisting of the costs of storage of spent nuclear fuel at the PrairieIsland and Monticello nuclear generating plants, costs related to the PrivateFuel Storage, LLC and costs relating to the 1994 and 2003 state legislationrelating to the storage of spent nuclear fuel at Prairie Island.  On July 31, 2001, the Court of FederalClaims granted NSP-Minnesota’s motion for partial summary judgment onliability.  The Court of Federal Claimshas directed the parties to be prepared for trial on this matter by Nov. 1, 2005.

 

On July 9, 2004, the federal Court of Appeals for the District ofColumbia issued a decision to consolidate cases challenging regulations anddecisions on the federal nuclear waste program. The Court of Appeals rejectedchallenges by the state of Nevada and

 

22

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other intervenors with respect to the majority of the licensingregulations of the NRC, the congressional resolution selecting Yucca Mountainas the site of the permanent repository, and the DOE and presidential actionsleading to the selection of Yucca Mountain. The Court of Appeals vacated the10,000 year compliance period adopted by EPA regulations governing spentnuclear fuel disposal and incorporated in the NRC regulations governing Yucca Mountainlicensing. Xcel Energy has not ascertained the impact of the decision on itsnuclear operations and storage of spent nuclear fuel; however, the decision mayresult in additional delay and uncertainty around disposal of spent nuclearfuel.

 

***St. Cloud Gas Explosion*****—Twenty-five lawsuits were filed as a result of a Dec. 11, 1998, gas explosionin St. Cloud, Minn. that killed four persons (including two employees ofNSP-Minnesota), injured several others and damaged numerous buildings. Most ofthe lawsuits named as defendants NSP-Minnesota, Xcel Energy’s Seren subsidiary,Cable Constructors, Inc. (CCI) (the contractor hired by Seren that struck themarked gas line), and Sirti, an architectural/engineering firm hired by Serenfor its St. Cloud cable installation project. The court granted the plaintiffs’request to amend the complaint to seek punitive damages against Seren and CCI.The plaintiffs brought a similar motion against NSP-Minnesota, which wassubsequently denied by the court. On Nov. 11, 2003, court-ordered mediation wasconducted. As a result of this mediation NSP-Minnesota reached a confidentialsettlement with a group of plaintiffs representing the most significant claimsasserted against NSP-Minnesota. In November and December of 2003,similar mediations were conducted that resulted in confidential settlementswith various plaintiffs representing the most significant claims assertedagainst Seren.  The remaining lawsuitswere settled in 2004.  The settlementswere paid primarily by Seren’s insurance carriers.  Remaining settlement payments byNSP-Minnesota are not material.

 

***Light Rail Lawsuit****—*In February 2001, NSP-Minnesotafiled a lawsuit in the federal district court in Minneapolis seekingreimbursement of costs for relocating electric utility lines to allow forconstruction of a light rail transit (LRT) line in downtown Minneapolis. In May2001, the Minnesota Department of Transportation and the Metropolitan Council(Defendants) obtained a preliminary injunction requiring NSP-Minnesota to movecertain facilities. NSP-Minnesota complied with the preliminary injunction andhas relocated the pertinent utility lines. NSP-Minnesota is capitalizing itscosts incurred as construction work in progress. In September 2002, thecourt granted Defendants’ motions for summary judgment and dismissedNSP-Minnesota’s claims. NSP-Minnesota appealed to the United States Court ofAppeals for the Eighth Circuit. In February 2004, the court of appealsaffirmed the district court decision. Further appellate review is not beingsought.  In August 2004, defendantsfiled a summary judgment motion in Federal District Court for attorney’s feesin the amount of $700,000, premised on an argument that pursuant to MinnesotaRule 8810.3300 NSP-Minnesota is liable for all claims occasioned by a failureto remove facilities from the right-of-way when ordered to do so.  On Feb. 3, 2005, the federal district courtdenied the Defendant’s claim for attorneys’ fees and granted NSP-Minnesota’smotion for summary judgment, dismissing the Defendant’s counterclaims.

 

***Other Matters***

 

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

 

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

 

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

 

**PART II**

 

**Item 5 — Market for Registrant’s Common Equity, RelatedStockholder Matters and****IssuerPurchases of Equity Securities**

 

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

 

NSP-Minnesota’s firstmortgage indenture places certain restrictions on the amount of cash dividendsit can pay to Xcel Energy, the holder of its common stock. Even with theserestrictions, NSP-Minnesota could have paid more than $833 million inadditional cash dividends on common stock at Dec. 31, 2004. In addition,NSP-Minnesota has dividend restrictions imposed by state regulatorycommissions, debt agreements and the SEC under the PUHCA limiting the amount ofdividends NSP-Minnesota can pay to Xcel Energy. These restrictions include, butmay not be limited to, the following:

 

•              maintenance of an equity ratio of 43.27percent to 52.91 percent;

 

•              payment of dividends only from retainedearnings; and

 

23

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•              debt covenant restrictions under the creditagreement for debt ratio.

 

The dividends declaredduring 2004 and 2003 were as follows:

 

| **(Thousands of dollars)  Quarter Ended** | ** ** |
|-------------------------------------------|------------|
| **March 31, 2004**                   | ** ** | **June 30, 2004** | ** ** | **Sept. 30, 2004** | ** ** | **Dec. 31, 2004** | ** ** |
| $                                         | 52,294     |   | $ | 53,598 |   | $ | 53,289 |   | $ | 53,033 |   |
|                                           |            |  |  |  |  |  |  |  |  |  |  |

 

| **March 31, 2003** | ** ** | **June 30, 2003** | ** ** | **Sept. 30, 2003** | ** ** | **Dec. 31, 2003** | ** ** |
|-------------------------|------------|------------------------|------------|--------------------|------------|-------------------|------------|
| $                       | 53,569     |                   | $          | 53,331             |       | $                 | 53,468     |   | $ | 53,852 |   |
|                         |            |                        |            |                    |            |                   |            |  |  |  |  |

 

**Item 6 —Selected Financial Data**

 

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

 

24

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

 

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

 

**ForwardLooking Information**

 

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

 

Except for the historicalstatements contained in this report, the matters discussed in the followingdiscussion and analysis are forward-looking statements that are subject to certainrisks, uncertainties and assumptions. Such forward-looking statements areintended to be identified in this document by the words “anticipate,” “believe,”“estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,”“possible,” “potential,” “should,” and similar expressions. Actual results mayvary materially. Factors that could cause actual results to differ materiallyinclude, but are not limited to:

 

•             generaleconomic conditions, including the availability of credit and its impact oncapital expenditures and the ability to obtain financing on favorable terms;

 

•             rating agency actions;

 

•             business conditions in the energy industry;

 

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

 

•             unusual weather;

 

•             changes in federal or state legislation;

 

•             geopolitical events, including war and actsof terrorism;

 

•             regulation; and

 

•             the other risk factors listed from time totime by NSP-Minnesota in reports filed with the SEC, including Exhibit 99.01 tothis Annual Report on Form 10-K for the year ended Dec. 31, 2004.

 

25

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

 

**Results ofOperations**

 

NSP-Minnesota’s net incomewas approximately $230.3 million for 2004, compared with approximately $192.9million for 2003.

 

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

 

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

 

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

 

Margins from commoditytrading activity are partially redistributed to PSCo and SPS pursuant to theJOA approved by the FERC. Margins received pursuant to the JOA are reflected aspart of Base Electric Utility Revenues.  Trading revenues, as discussed in Note 1 tothe Consolidated Financial Statements, are reported net of trading costs (i.e.,on a margin basis) in the Consolidated Statements of Income.  Commodity trading costs include fuel,purchased power, transmission and other related costs. The following tabledetails base electric utility, short-term wholesale and commodity tradingactivities:

 
| ** **                                              | ** ** | **Base  Electric  Utility** | ** ** | **Short-Term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Totals** | ** ** |
|---------------------------------------------------------|------------|-----------------------------|------------|---------------------------|------------|------------------------|------------|--------------------------|------------|
| ** **                                              | ** ** | **(Millions of dollars)**   | ** ** |
| **2004**                                                |       |                        |       |                      |       |                   |       |                     |       |
| Electric  utility revenue (excluding commodity trading) |       | $                           | 2,434      |                      | $          | 149                    |       | $                        | —     |   | $ | 2,583 |   |
| Electric  fuel and purchased power                      |       | (917                        | )          | (60                       | )          | —                 |       | (977                     | )          |
| Commodity  trading revenue                              |       | —                      |       | —                    |       | 123                    |       | 123                      |       |
| Commodity  trading costs                                |       | —                      |       | —                    |       | (120                   | )          | (120                     | )          |
| Gross margin  before operating expenses                 |       | $                           | 1,517      |                      | $          | 89                     |       | $                        | 3          |   | $ | 1,609 |   |
| Margin as a  percentage of revenue                      |       | 62.3                        | %          | 59.7                      | %          | 2.4                    | %          | 59.5                     | %          |
|                                                    |       |                        |       |                      |       |                   |       |                     |       |
| **2003**                                                |       |                        |       |                      |       |                   |       |                     |       |
| Electric  utility revenue (excluding commodity trading) |       | $                           | 2,350      |                      | $          | 128                    |       | $                        | —     |   | $ | 2,478 |   |
| Electric  fuel and purchased power                      |       | (820                        | )          | (68                       | )          | —                 |       | (888                     | )          |
| Commodity  trading revenue                              |       | —                      |       | —                    |       | 89                     |       | 89                       |       |
| Commodity  trading costs                                |       | —                      |       | —                    |       | (81                    | )          | (81                      | )          |
| Gross margin  before operating expenses                 |       | $                           | 1,530      |                      | $          | 60                     |       | $                        | 8          |   | $ | 1,598 |   |
| Margin as a  percentage of revenue                      |       | 65.1                        | %          | 46.9                      | %          | 9.0                    | %          | 62.3                     | %          |

 

The following summarizes thecomponents of the changes in base electric revenue and base electric margin forthe year ended Dec. 31:

 

***Base Electric Revenue***

 

| **(Millions of dollars)**                         | ** ** | **2004 vs 2003** | ** ** |
|---------------------------------------------------|------------|------------------|------------|
| Fuel Cost  recovery                               |       | $                | 63.3       |   |
| Sales growth  (excluding weather impact)          |       | 30.9             |       |
| Estimated  impact of weather                      |       | (30.1            | )          |
| Interchange  agreement billing with NSP-Wisconsin |       | (7.8             | )          |
| Firm  wholesale                                   |       | 6.0              |       |
| Transmission  and other                           |       | 21.7             |       |
| Total base  electric revenue increase             |       | $                | 84.0       |   |

 

26

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***Base Electric Margin***

 

| **(Millions of dollars)**                                                  | ** ** | **2004 vs 2003** | ** ** |
|----------------------------------------------------------------------------|------------|------------------|------------|
| Sales growth  (excluding weather impact)                                   |       | $                | 23.7       |   |
| Estimated  impact of weather                                               |       | (23.0            | )          |
| Interchange  agreement* *— prior  period fixed charge adjustment |       | (19.2            | )          |
| Purchased  capacity costs                                                  |       | (6.7             | )          |
| Firm  wholesale                                                            |       | 4.0              |       |
| Renewable  development fund recovery                                       |       | (4.7             | )          |
| Transmission  and other                                                    |       | 12.9             |       |
| Total base  electric decrease                                              |       | $                | (13.0      | ) |

 

Short-term wholesaleincreased in 2004, compared with 2003, due to favorable market conditions.

 

***Natural Gas Utility Margins*****— The following table details the change innatural gas revenue and margin. The cost of natural gas tends to vary withchanging sales requirements and unit cost of natural gas purchases. However,due to purchased natural gas cost recovery mechanisms for retail customers,fluctuations in the cost of natural gas have little effect on natural gasmargin.

 
| ** **                                | ** ** | **2004**                  | ** ** | **2003** | ** ** |
|-------------------------------------------|------------|---------------------------|------------|----------|------------|
| ** **                                | ** ** | **(Millions of dollars)** | ** ** |
| Natural gas  utility revenue              |       | $                         | 715        |     | $          | 675 |   |
| Cost of  natural gas sold and transported |       | (557                      | )          | (517     | )          |
| Natural gas  utility margin               |       | $                         | 158        |     | $          | 158 |   |

 

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

 

***Natural Gas Revenue***

 

| **(Millions of dollars)**                         | ** ** | **2004 vs 2003** | ** ** |
|---------------------------------------------------|------------|------------------|------------|
| Purchased  gas adjustment clause recovery         |       | $                | 42.4       |   |
| Estimated  impact of weather on firm sales volume |       | (7.0             | )          |
| Sales growth  (excluding weather impact)          |       | (3.0             | )          |
| Off system  sales                                 |       | 9.0              |       |
| Transportation  and other                         |       | (0.9             | )          |
| Total  natural gas revenue increase               |       | $                | 40.5       |   |

 

Naturalgas revenue increased primarily due to higher natural gas costs in 2004, whichare passed through to customers.  Retailgas weather-normalized sales declined in 2004, largely due to the rising costof natural gas and its impact on customer usage.

 

***Natural Gas Margin***

 

| **(Millions of dollars)**                         | ** ** | **2004 vs 2003** | ** ** |
|---------------------------------------------------|------------|------------------|------------|
| Sales growth  (excluding weather impact)          |       | $                | 0.1        |   |
| Estimated  impact of weather on firm sales volume |       | (2.2             | )          |
| Off system  sales                                 |       | 0.7              |       |
| Regulatory  adjustments                           |       | 0.9              |       |
| Transportation  and other                         |       | 1.0              |       |
| Total  natural gas margin increase                |       | $                | 0.5        |   |

 

***Non-Fuel Operating Expense and Other Costs*****— The following summarizes the components ofthe changes in other utility operating and maintenance expense for the yearended Dec. 31:

 

27

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| **(Millions of dollars)**                                                       | ** ** | **2004 vs 2003** | ** ** |
|---------------------------------------------------------------------------------|------------|------------------|------------|
| Lower  compensation costs                                                       |       | $                | (16.7      | ) |
| Lower plant  outage costs                                                       |       | (12.9            | )          |
| Lower  private fuel storage costs                                               |       | (5.6             | )          |
| Higher  employee benefit costs                                                  |       | 7.6              |       |
| Costs offset  in revenue                                                        |       | 6.4              |       |
| Higher  interchange expense with NSP-Wisconsin (see Note 15)                    |       | 2.9              |       |
| Higher bad  debt costs                                                          |       | 2.0              |       |
| Unfavorable  obsolete inventory write-off and inventory adjustments             |       | 1.8              |       |
| Higher information  technology costs                                            |       | 1.6              |       |
| Higher costs  related to Sarbanes-Oxley and audit fees                          |       | 1.6              |       |
| Higher power  plant related costs related to projects moved from 2005 into 2004 |       | 1.3              |       |
| Other                                                                           |       | 1.6              |       |
| Total other  utility operating and maintenance expense decrease                 |       | $                | (8.4       | ) |

 

Depreciationand amortization expense decreased by approximately $16.6 million, or 4.7percent, for 2004 compared with 2003. The reduction is largely due to a regulatory decision.  In 2004, as a result of an MPUC order,NSP-Minnesota modified its decommissioning expense recognition, which served toreduce decommissioning accruals by approximately $18 million when compared with2003.

 

Other income increased byapproximately $12.0 million due primarily to higher allowance for funds usedduring construction in 2004 and lower non-operating amortizations due to the2003 write-off of an intangible asset.

 

Interest charges andfinancing costs decreased by approximately $7.1 million, or 5.2 percent, for2004, compared with 2003. The decrease is due to the issuance of debtduring 2003 to refinance higher coupon debt, including the redemption of thepreferred securities of NSP-Minnesota’s subsidiary trust.  Financing costs were further reduced byhigher allowance for funds used during construction in 2004.

 

***Income Taxes***— Income tax expense increased by approximately $18.1 million in 2004,compared with 2003.  The increase wasprimarily due to higher income levels. The effective tax rate was 29.1 percent for the period ended Dec. 31,2004, compared with 28.4 percent for the same period in 2003.  Significant tax benefits were recorded duringboth periods due to the resolution of tax audit issues, largely related toprior periods, as discussed below.

 

The significant auditactivity that occurred late in 2003 continued in 2004.  During 2004, NSP-Minnesota concludedIRS income tax audit and appeal activities spanning several examination cyclesdating back to 1993.  In addition, theIRS nearly completed the examination cycle ended 2001 and began its review of NSP-Minnesota’s2002 and 2003 tax years.

 

Income taxbenefits of $12.5 million were recorded in 2004, including $4.1 million relatedto the successful resolution of various IRS audit issues and other adjustmentsto current and deferred taxes related to prior years, $7.0 million for the 2003return to accrual true-up and $1.4 million from revisions to benefits relatedto foreign power sales.  Excluding thetax benefits, the effective rate for the year 2004 would have been 32.9percent.

 

The income taxexpense recorded in 2003 included $13 million in tax benefits to reflect thesuccessful resolution of various open tax audit issues related to prioryears.  The resolved issues included thetax deductibility of certain merger costs associated with the merger to formXcel Energy and the deductibility, for state tax purposes, of certain taxbenefit transfer lease benefits. Excluding these tax benefits, the effective rate for the year 2003 wouldhave been 33.5 percent.

 

28

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**Item 7A — Quantitative and Qualitative DisclosuresAbout Market Risk**

 

**Derivatives,Risk Management and Market Risk**

 

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

 

***Commodity Price Risk —*** NSP-Minnesota is exposed to commodity pricerisk in its generation and retail distribution operations.  Commodity price risk is managed by enteringinto both long- and short-term physical purchase and sales contracts forelectric power, natural gas, coal and fuel oil. Commodity price risk is also managed through the use of financialderivative instruments.  NSP-Minnesota’srisk management policy allows it to manage commodity price risk within eachrate-regulated operation to the extent such exposure exists.

 

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

 

Certain contracts within thescope of these activities qualify for hedge accounting treatment under SFAS No.133 — “Accounting for Derivative Instruments and Hedging Activities,” asamended, while others are subject to the fair value requirements of thispronouncement.

 

See Note 9 to the ConsolidatedFinancial Statements for a discussion of the various trading and hedgingcontracts of NSP-Minnesota.

 

NSP-Minnesota’s short-termwholesale and commodity trading operations measure the outstanding riskexposure to price changes on transactions, contracts and obligations that havebeen entered into, but not closed, using an industry standard methodology knownas VaR. VaR expresses the potential change in fair value on the outstandingtransactions, contracts and obligations over a particular period of time, witha given confidence interval under normal market conditions. NSP-Minnesotautilizes the variance/covariance approach in calculating VaR. The VaR modelemploys a 95-percent confidence interval level based on historical pricemovement, lognormal price distribution assumption, delta half-gamma approachfor non-linear instruments and a three-day holding period for both electricityand natural gas.  Previously,NSP-Minnesota calculated VaR using a holding period of five days forelectricity and two days for natural gas. However, the methodology was changed to ensure consistency in riskmeasurement across both commodities. NSP-Minnesota’s revised holding periods remain consistent with currentindustry practice.  VaR using the currentmethodology for 2004 and previous methodology for 2003 are as follows:

 

As of Dec. 31, 2004, thecalculated VaRs using the current methodology were:

 

| ** **                | ** ** | **Year ended**    | ** ** | **During 2004** | ** ** |
|---------------------------|------------|-------------------|------------|-----------------|------------|
| **Current Methodology**   | ** ** | **Dec. 31, 2004** | ** ** | **Average**     | ** ** | **High** | ** ** | **Low** | ** ** |
| **(Millions of dollars)** | ** ** | ** **        | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Commodity  trading (a)    |       | $                 | 0.29       |            | $          | 0.97 |   | $ | 2.09 |   | $ | 0.27 |   |
|                           |            |                   |            |                 |            |  |  |  |  |  |  |  |  |

 

----

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

 

29

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As of Dec. 31, 2003, thecalculated VaRs using the previous methodology were:

 

| ** **                      | ** ** | **Year ended**    | ** ** | **During 2003** | ** ** |
|---------------------------------|------------|-------------------|------------|-----------------|------------|
| **Previous Methodology**        | ** ** | **Dec. 31, 2003** | ** ** | **Average**     | ** ** | **High** | ** ** | **Low** | ** ** |
| **(Millions of dollars)**       | ** ** | ** **        | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Electric  commodity trading (a) |       | $                 | 0.92       |            | $          | 0.70 |   | $ | 1.51 |   | $ | 0.29 |   |
|                                 |            |                   |            |                 |            |  |  |  |  |  |  |  |  |

 

----

(a)      Comprises transactions for both NSP-Minnesotaand 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.

 

NSP-Minnesotamay engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges isinitially recorded in Other Comprehensive Income.  Reclassification of unrealized gains orlosses on cash flow hedges of variable rate debt instruments from OtherComprehensive Income into earnings occurs as interest payments are accrued onthe debt instrument and generally offsets the change in the interest accrued onthe underlying variable rate debt.  Thefair value of interest rate swaps is determined through counterpartyvaluations, internal valuations and broker quotes.  There have been no material changes in thetechniques or models used in the valuation of interest rate swaps during theperiods presented.

 

AtDec. 31, 2004 and 2003, a 100-basis-point change in the benchmark rate onNSP-Minnesota’s variable rate debt would impact pretax interest expense byapproximately $0.3 million and $0.2 million, respectively.

 

NSP-Minnesota also maintains trust funds, as required by the NRC, tofund certain costs of nuclear decommissioning, which are subject to interestrate risk and equity price risk.  As ofDec. 31, 2004 and 2003, these funds were invested primarily in domestic andinternational equity securities and fixed-rate fixed-income securities.  Per NRC mandates, these funds may be usedonly for activities related to nuclear decommissioning.  The accounting for nuclear decommissioningrecognizes that costs are recovered through rates; therefore fluctuations inequity prices or interest rates do not have an impact on earnings.

 

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

 

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

 

30

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

 

# **REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

# ** **

Board of Directors and Stockholders

Northern States Power Company—Minnesota

 

We have audited the accompanying consolidated balance sheets andconsolidated statements of capitalization of Northern States PowerCompany—Minnesota (a Minnesota corporation) and subsidiaries (the “Company”) asof December 31, 2004 and 2003, and the related consolidated statements ofincome, stockholder’s equity and other comprehensive income (loss) and cashflows for each of the three years in the period ended December 31, 2004. Ouraudit also included the financial statement schedule listed in the Index atItem 15. These financial statements and financial statement schedule are theresponsibility of the Company’s management. Our responsibility is to express anopinion on the financial statements and financial statement schedules based onour 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. An audit includesconsideration 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 no suchopinion. An audit also includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements, assessing theaccounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation. We believethat our audits provide a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly,in all material respects, the financial position of Northern States PowerCompany—Minnesota and subsidiaries as of December 31, 2004 and 2003, and theresults of their operations and their cash flows for each of the three years inthe period ended December 31, 2004, in conformity with accounting principlesgenerally accepted in the United States of America. Also, in our opinion, suchfinancial statement schedule, when considered in relation to the basicconsolidated financial statements taken as a whole, present fairly in allmaterial respects the information set forth therein.

 
| /S/ DELOITTE & TOUCHE LLP |   |
|-------------------------------|--------|
| Minneapolis, Minnesota        |
| March 3, 2005                 |

 

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**NSP-MINNESOTA**

**CONSOLIDATED STATEMENTS OF INCOME**

 
|                                                                                           |   | **Year Ended Dec. 31,**    |      |
|------------------------------------------------------------------------------------------------|--------|----------------------------|-----------|
|                                                                                           |   | **2004**                   |      | **2003** |   | **2002** |   |
|                                                                                           |   | **(Thousands of dollars)** |      |
| Operating  revenues:                                                                           |   |                       |      |   |   |   |   |
| Electric  utility                                                                              |   | $                          | 2,585,356 |   | $ | 2,485,742 |   | $ | 2,362,672 |   |
| Natural gas  utility                                                                           |   | 715,071                    |      | 674,530 |   | 489,572 |   |
| Other                                                                                          |   | 19,135                     |      | 17,180 |   | 30,875 |   |
| Total  operating revenues                                                                      |   | 3,319,562                  |      | 3,177,452 |   | 2,883,119 |   |
|                                                                                           |   |                       |      |   |   |   |   |
| Operating  expenses:                                                                           |   |                       |      |   |   |   |   |
| Electric  fuel and purchased power                                                             |   | 976,639                    |      | 888,274 |   | 789,379 |   |
| Cost of  natural gas sold and transported                                                      |   | 556,662                    |      | 516,631 |   | 343,700 |   |
| Operating and  maintenance expenses                                                            |   | 845,209                    |      | 853,656 |   | 829,178 |   |
| Depreciation  and amortization                                                                 |   | 336,744                    |      | 353,341 |   | 354,157 |   |
| Taxes (other  than income taxes)                                                               |   | 172,675                    |      | 170,318 |   | 168,721 |   |
| Total  operating expenses                                                                      |   | 2,887,929                  |      | 2,782,220 |   | 2,485,135 |   |
|                                                                                           |   |                       |      |   |   |   |   |
| Operating  income                                                                              |   | 431,633                    |      | 395,232 |   | 397,984 |   |
|                                                                                           |   |                       |      |   |   |   |   |
| Other income  (expense):                                                                       |   |                       |      |   |   |   |   |
| Interest and  other income, net of nonoperating expenses (see Note 8)                          |   | 1,089                      |      | (2,800 | ) | 19,578 |   |
| Allowance  for funds used during construction – equity                                    |   | 20,747                     |      | 12,674 |   | 5,491 |   |
| Total other  income                                                                            |   | 21,836                     |      | 9,874 |   | 25,069 |   |
|                                                                                           |   |                       |      |   |   |   |   |
| Interest  charges and financing costs                                                          |   |                       |      |   |   |   |   |
| Interest  charges — including financing costs of $8,258, $8,989 and $5,241,  respectively |   | 142,147                    |      | 135,764 |   | 107,470 |   |
|                                                                                           |
| Allowance  for funds used during construction – debt                                      |   | (13,565                    | )         | (9,311 | ) | (8,530 | ) |
| Distributions  on redeemable preferred securities of subsidiary trust                          |   | —                     |      | 9,187 |   | 15,750 |   |
| Total  interest charges and financing costs                                                    |   | 128,582                    |      | 135,640 |   | 114,690 |   |
|                                                                                           |   |                       |      |   |   |   |   |
| Income  before income taxes                                                                    |   | 324,887                    |      | 269,466 |   | 308,363 |   |
| Income taxes                                                                                   |   | 94,613                     |      | 76,524 |   | 108,141 |   |
| Net income                                                                                     |   | $                          | 230,274   |   | $ | 192,942 |   | $ | 200,222 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTA**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

 
|                                                                                           |   | **Year Ended Dec. 31,**    |    |
|------------------------------------------------------------------------------------------------|--------|----------------------------|---------|
|                                                                                           |   | **2004**                   |    | **2003** |   | **2002** |   |
|                                                                                           |   | **(Thousands of dollars)** |    |
| Operating  activities:                                                                         |   |                       |    |   |   |   |   |
| Net income                                                                                     |   | $                          | 230,274 |   | $ | 192,942 |   | $ | 200,222 |   |
| Adjustments  to reconcile net income to cash provided by operating activities:                 |   |                       |    |   |   |   |   |
| Depreciation  and amortization                                                                 |   | 351,887                    |    | 352,630 |   | 366,362 |   |
| Nuclear fuel  amortization                                                                     |   | 43,296                     |    | 43,401 |   | 48,675 |   |
| Deferred  income taxes                                                                         |   | 20,545                     |    | 1,561 |   | (26,280 | ) |
| Amortization  of investment tax credits                                                        |   | (7,150                     | )       | (7,365 | ) | (7,490 | ) |
| Allowance  for equity funds used during construction                                           |   | (20,747                    | )       | (12,674 | ) | (5,491 | ) |
| Gain on sale  of nonutility property                                                           |   | —                     |    | — |   | (6,785 | ) |
| Change in  accounts receivable                                                                 |   | (18,185                    | )       | (46,150 | ) | (7,933 | ) |
| Change in  accounts receivable from affiliates                                                 |   | 40,466                     |    | (30,923 | ) | (17,893 | ) |
| Change in  inventories                                                                         |   | (12,622                    | )       | (6,206 | ) | (4,296 | ) |
| Change in  other current assets                                                                |   | (73,706                    | )       | (45,026 | ) | 21,712 |   |
| Change in  accounts payable                                                                    |   | 27,032                     |    | 17,757 |   | (12,745 | ) |
| Change in  other current liabilities                                                           |   | (24,204                    | )       | (75,155 | ) | 59,929 |   |
| Change in  other assets                                                                        |   | (9,396                     | )       | (8,205 | ) | (60,052 | ) |
| Change in  other liabilities                                                                   |   | 92,246                     |    | (7,404 | ) | 75,677 |   |
| Net cash  provided by operating activities                                                     |   | 639,736                    |    | 369,183 |   | 623,612 |   |
|                                                                                           |   |                       |    |   |   |   |   |
| Investing  activities:                                                                         |   |                       |    |   |   |   |   |
| Utility  capital/construction expenditures                                                     |   | (641,476                   | )       | (352,389 | ) | (383,857 | ) |
| Allowance  for equity funds used during construction                                           |   | 20,747                     |    | 12,674 |   | 5,491 |   |
| Investments  in and advances to affiliates                                                     |   | (7,790                     | )       | (16,830 | ) | 27,475 |   |
| Proceeds  from sale of property                                                                |   | —                     |    | — |   | 11,152 |   |
| Investments  in external decommissioning fund                                                  |   | (80,582                    | )       | (80,581 | ) | (57,830 | ) |
| Restricted  cash                                                                               |   | —                     |    | 23,000 |   | (23,000 | ) |
| Other  investments                                                                             |   | (1,293                     | )       | (4,138 | ) | (4,939 | ) |
| Net cash  used in investing activities                                                         |   | (710,394                   | )       | (418,264 | ) | (425,508 | ) |
|                                                                                           |   |                       |    |   |   |   |   |
| Financing  activities:                                                                         |   |                       |    |   |   |   |   |
| Short-term  borrowings — net                                                              |   | 32,000                     |    | 57,931 |   | (381,115 | ) |
| Proceeds  from issuance of long-term debt                                                      |   | 10                         |    | 372,943 |   | 624,892 |   |
| Repayment of  long-term debt and trust preferred securities, including reacquisition  premiums |   | (4,508                     | )       | (426,568 | ) | (4,876 | ) |
| Capital  contributions from parent                                                             |   | 180,408                    |    | 29,100 |   | 51,714 |   |
| Dividends  and cash distributions paid to parent                                               |   | (213,033                   | )       | (212,648 | ) | (195,550 | ) |
| Net cash  provided by (used in) financing activities                                           |   | (5,123                     | )       | (179,242 | ) | 95,065 |   |
|                                                                                           |   |                       |    |   |   |   |   |
| Net  (decrease) increase in cash and cash equivalents                                          |   | (75,781                    | )       | (228,323 | ) | 293,169 |   |
| Cash and  cash equivalents at beginning of year                                                |   | 82,015                     |    | 310,338 |   | 17,169 |   |
| Cash and  cash equivalents at end of year                                                      |   | $                          | 6,234   |   | $ | 82,015 |   | $ | 310,338 |   |
|                                                                                           |   |                       |    |   |   |   |   |
| Supplemental  disclosure of cash flow information                                              |   |                       |    |   |   |   |   |
| Cash paid  for interest (net of amounts capitalized)                                           |   | $                          | 123,705 |   | $ | 120,993 |   | $ | 75,315 |   |
| Cash paid  for income taxes (net of refunds received)                                          |   | $                          | 32,796  |   | $ | 181,701 |   | $ | 83,636 |   |

 

See Notes to Consolidated Financial Statements

 

33

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**NSP-MINNESOTA**

**CONSOLIDATED BALANCE SHEETS**

 
| ** **                                                                                         | ** ** | **Dec. 31,  2004**         | ** ** | **Dec. 31,  2003** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|----------------------------|------------|--------------------|------------|
|                                                                                               |       | **(Thousands of dollars)** |       |
| **ASSETS**                                                                                         |       |                       |       |               |       |
| Current  assets:                                                                                   |       |                       |       |               |       |
| Cash and  cash equivalents                                                                         |       | $                          | 6,234      |               | $          | 82,015 |   |
| Notes  receivable from affiliates                                                                  |       | 31,500                     |       | 23,710             |       |
| Accounts  receivable — net of allowance for bad debts: $7,845 and $7,581, respectively        |       | 296,331                    |       | 278,146            |       |
| Accounts  receivable from affiliates                                                               |       | 8,350                      |       | 48,816             |       |
| Accrued  unbilled revenues                                                                         |       | 172,512                    |       | 125,872            |       |
| Materials  and supplies inventories — at average cost                                         |       | 96,953                     |       | 100,297            |       |
| Fuel  inventory — at average cost                                                             |       | 31,483                     |       | 27,727             |       |
| Natural gas  inventory — at average cost                                                      |       | 55,689                     |       | 43,479             |       |
| Income tax  receivable                                                                             |       | —                     |       | 11,249             |       |
| Derivative  instruments valuation — at market                                                 |       | 62,272                     |       | 26,666             |       |
| Prepayments  and other                                                                             |       | 32,719                     |       | 30,011             |       |
| Total  current assets                                                                              |       | 794,043                    |       | 797,988            |       |
|                                                                                               |       |                       |       |               |       |
| Property,  plant and equipment, at cost:                                                           |       |                       |       |               |       |
| Electric  utility plant                                                                            |       | 7,586,873                  |       | 7,268,609          |       |
| Natural gas  utility plant                                                                         |       | 778,256                    |       | 746,835            |       |
| Construction  work in progress                                                                     |       | 438,474                    |       | 328,880            |       |
| Other                                                                                              |       | 406,229                    |       | 400,448            |       |
| Total  property, plant and equipment                                                               |       | 9,209,832                  |       | 8,744,772          |       |
| Less  accumulated depreciation                                                                     |       | (4,175,557                 | )          | (3,991,875         | )          |
| Nuclear fuel  — net of accumulated amortization: $1,145,228 and $1,101,932, respectively      |       | 74,308                     |       | 80,289             |       |
| Net  property, plant and equipment                                                                 |       | 5,108,583                  |       | 4,833,186          |       |
|                                                                                               |       |                       |       |               |       |
| Other  assets:                                                                                     |       |                       |       |               |       |
| Nuclear  decommissioning fund investments                                                          |       | 918,442                    |       | 779,382            |       |
| Other  investments                                                                                 |       | 24,039                     |       | 25,055             |       |
| Regulatory  assets                                                                                 |       | 476,485                    |       | 492,491            |       |
| Prepaid  pension asset                                                                             |       | 361,446                    |       | 317,956            |       |
| Derivative  instruments valuation — at market                                                 |       | 234,509                    |       | 177,581            |       |
| Other                                                                                              |       | 47,968                     |       | 59,463             |       |
| Total other  assets                                                                                |       | 2,062,889                  |       | 1,851,928          |       |
| Total assets                                                                                       |       | $                          | 7,965,515  |               | $          | 7,483,102 |   |
| **LIABILITIES  AND EQUITY**                                                                        |       |                       |       |               |       |
| Current  liabilities:                                                                              |       |                       |       |               |       |
| Current  portion of long-term debt                                                                 |       | $                          | 82,185     |               | $          | 4,502 |   |
| Short-term  debt                                                                                   |       | 90,000                     |       | 58,000             |       |
| Accounts  payable                                                                                  |       | 287,531                    |       | 250,628            |       |
| Accounts  payable to affiliates                                                                    |       | 23,013                     |       | 32,884             |       |
| Taxes  accrued                                                                                     |       | 147,144                    |       | 116,862            |       |
| Accrued  interest                                                                                  |       | 42,998                     |       | 44,485             |       |
| Dividends  payable to parent                                                                       |       | 53,033                     |       | 53,852             |       |
| Derivative  instruments valuation — at market                                                 |       | 58,366                     |       | 67,664             |       |
| Other                                                                                              |       | 51,560                     |       | 44,863             |       |
| Total  current liabilities                                                                         |       | 835,830                    |       | 673,740            |       |
|                                                                                               |       |                       |       |               |       |
| Deferred  credits and other liabilities:                                                           |       |                       |       |               |       |
| Deferred  income taxes                                                                             |       | 785,046                    |       | 738,677            |       |
| Deferred  investment tax credits                                                                   |       | 59,119                     |       | 66,681             |       |
| Regulatory  liabilities                                                                            |       | 944,364                    |       | 889,152            |       |
| Asset  retirement obligations (see Note 12)                                                        |       | 1,091,089                  |       | 1,024,529          |       |
| Derivative  instruments valuation — at market                                                 |       | 246,872                    |       | 212,263            |       |
| Benefit  obligations and other                                                                     |       | 136,131                    |       | 128,247            |       |
| Total  deferred credits and other liabilities                                                      |       | 3,262,621                  |       | 3,059,549          |       |
|                                                                                               |       |                       |       |               |       |
| Long-term  debt                                                                                    |       | 1,859,737                  |       | 1,940,958          |       |
| Common stock  — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000  shares |       | 10                         |       | 10                 |       |
| Premium on  common stock                                                                           |       | 1,023,377                  |       | 842,969            |       |
| Retained  earnings                                                                                 |       | 983,940                    |       | 965,880            |       |
| Accumulated  other comprehensive loss                                                              |       | —                     |       | (4                 | )          |
| Total common  stockholder’s equity                                                            |       | 2,007,327                  |       | 1,808,855          |       |
| Commitments  and contingencies (see Note 11)                                                       |       |                       |       |               |       |
| Total  liabilities and equity                                                                      |       | $                          | 7,965,515  |               | $          | 7,483,102 |   |

 

See Notes to Consolidated Financial Statements

 

34

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**NSP-MINNESOTA**

**CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY**

**AND OTHER COMPREHENSIVE INCOME (LOSS)**

 
| ** **                                                                            | ** ** | ** **                                            | ** ** | ** ** | ** ** | **Premium on  Common Stock** | ** ** | **Retained  Earnings** | ** ** | **Leveraged  ESOP** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** ** | **Total  Stockholder’s  Equity** | ** ** |
|---------------------------------------------------------------------------------------|------------|-------------------------------------------------------|------------|------------|------------|------------------------------|------------|------------------------|------------|---------------------|------------|------------------------------------------------------|------------|---------------------------------------|------------|
| **Common Stock**                                                                      |
| **Shares**                                                                            | ** ** | **Amount**                                            |
| ** **                                                                            | ** ** | **(Thousands of dollars, except  share information)** | ** ** |
| ** **                                                                            | ** ** | ** **                                            | ** ** | ** ** | ** ** | ** **                   | ** ** | ** **             | ** ** | ** **          | ** ** | ** **                                           | ** ** | ** **                            | ** ** |
| Balance at  Dec. 31, 2001                                                             |       | 1,000,000                                             |       | $          | 10         |                         | $          | 762,155                |       | $                   | 990,435    |                                                 | $          | (18,564                               | )          | $ | 123 |   | $ | 1,734,159 |   |
| Net income                                                                            |       |                                                  |       |       |       |                         |       | 200,222                |       |                |       |                                                 |       | 200,222                               |       |
| Net  derivative instrument fair value changes during the period, net of tax of  $(83) |       |                                                  |       |       |       |                         |       |                   |       |                |       | (121                                                 | )          | (121                                  | )          |
| Unrealized  loss-marketable securities, net of tax of $6                              |       |                                                  |       |       |       |                         |       |                   |       |                |       | (11                                                  | )          | (11                                   | )          |
| Comprehensive  income for 2002                                                        |       |                                                  |       |       |       |                         |       |                   |       |                |       |                                                 |       | 200,090                               |       |
| Common  dividends declared to parent                                                  |       |                                                  |       |       |       |                         |       | (203,499               | )          |                |       |                                                 |       | (203,499                              | )          |
| Contribution  of capital by parent                                                    |       |                                                  |       |       |       | 51,714                       |       |                   |       |                |       |                                                 |       | 51,714                                |       |
| Repayment of  ESOP loan                                                               |       |                                                  |       |       |       |                         |       |                   |       | 18,564              |       |                                                 |       | 18,564                                |       |
| Balance at  Dec. 31, 2002                                                             |       | 1,000,000                                             |       | $          | 10         |                         | $          | 813,869                |       | $                   | 987,158    |                                                 | $          | —                                |       | $ | (9 | ) | $ | 1,801,028 |   |
|                                                                                  |       |                                                  |       |       |       |                         |       |                   |       |                |       |                                                 |       |                                  |       |
| Net income                                                                            |       |                                                  |       |       |       |                         |       | 192,942                |       |                |       |                                                 |       | 192,942                               |       |
| Unrealized  gain-marketable securities, net of tax of $(4)                            |       |                                                  |       |       |       |                         |       |                   |       |                |       | 5                                                    |       | 5                                     |       |
| Comprehensive  income for 2003                                                        |       |                                                  |       |       |       |                         |       |                   |       |                |       |                                                 |       | 192,947                               |       |
| Common  dividends declared to parent                                                  |       |                                                  |       |       |       |                         |       | (214,220               | )          |                |       |                                                 |       | (214,220                              | )          |
| Contribution  of capital by parent                                                    |       |                                                  |       |       |       | 29,100                       |       |                   |       |                |       |                                                 |       | 29,100                                |       |
| Balance at  Dec. 31, 2003                                                             |       | 1,000,000                                             |       | $          | 10         |                         | $          | 842,969                |       | $                   | 965,880    |                                                 | $          | —                                |       | $ | (4 | ) | $ | 1,808,855 |   |
|                                                                                  |       |                                                  |       |       |       |                         |       |                   |       |                |       |                                                 |       |                                  |       |
| Net income                                                                            |       |                                                  |       |       |       |                         |       | 230,274                |       |                |       |                                                 |       | 230,274                               |       |
| Unrealized  gain-marketable securities, net of tax of $(2)                            |       |                                                  |       |       |       |                         |       |                   |       |                |       | 4                                                    |       | 4                                     |       |
| Comprehensive  income for 2004                                                        |       |                                                  |       |       |       |                         |       |                   |       |                |       |                                                 |       | 230,278                               |       |
| Common  dividends declared to parent                                                  |       |                                                  |       |       |       |                         |       | (212,214               | )          |                |       |                                                 |       | (212,214                              | )          |
| Contribution  of capital by parent                                                    |       |                                                  |       |       |       | 180,408                      |       |                   |       |                |       |                                                 |       | 180,408                               |       |
| Balance at  Dec. 31, 2004                                                             |       | 1,000,000                                             |       | $          | 10         |                         | $          | 1,023,377              |       | $                   | 983,940    |                                                 | $          | —                                |       | $ | — |   | $ | 2,007,327 |   |

 

See Notes to Consolidated Financial Statements

 

35

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**NSP-MINNESOTA**

**CONSOLIDATED STATEMENTS OF CAPITALIZATION**

 
| ** **                                                                                                          | ** ** | **Dec. 31,**               | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|----------------------------|------------|
| ** **                                                                                                          | ** ** | **2004**                   | ** ** | **2003** | ** ** |
| ** **                                                                                                          | ** ** | **(Thousands of dollars)** | ** ** |
| **Long-Term  Debt**                                                                                                 |       |                       |       |   |   |
| First  Mortgage Bonds, Series due:                                                                                  |       |                       |       |   |   |   |   |
| Dec. 1, 2005  — 2006, 4% — 4.1%                                                                           |       | $                          | 4,750      | (a) | $ | 6,990 | (a) |
| Dec. 1,  2005, 6.125%                                                                                               |       | 70,000                     |       | 70,000 |   |
| Aug. 1,  2006, 2.875%                                                                                               |       | 200,000                    |       | 200,000 |   |
| Aug. 1,  2010, 4.75%                                                                                                |       | 175,000                    |       | 175,000 |   |
| Aug. 28,  2012, 8%                                                                                                  |       | 450,000                    |       | 450,000 |   |
| March 1,  2019, 8.5%                                                                                           |       | 27,900                     | (b)        | 27,900 | (b) |
| Sept. 1,  2019, 8.5%                                                                                                |       | 100,000                    | (b)        | 100,000 | (b) |
| July 1,  2025, 7.125%                                                                                          |       | 250,000                    |       | 250,000 |   |
| March 1,  2028, 6.5%                                                                                           |       | 150,000                    |       | 150,000 |   |
| April 1,  2030, 8.5%                                                                                           |       | 69,000                     | (b)        | 69,000 | (b) |
| Dec. 1, 2005  — 2008, 4.4% — 5%                                                                           |       | 9,790                      | (a)        | 11,990 | (a) |
| Senior Notes  due Aug. 1, 2009, 6.875%                                                                              |       | 250,000                    |       | 250,000 |   |
| Retail Notes  due July 1, 2042, 8%                                                                             |       | 185,000                    |       | 185,000 |   |
| Other                                                                                                               |       | 8,241                      |       | 8,301 |   |
| Unamortized  discount                                                                                               |       | (7,759                     | )          | (8,721 | ) |
| Total                                                                                                               |       | 1,941,922                  |       | 1,945,460 |   |
| Less current  maturities                                                                                            |       | 82,185                     |       | 4,502 |   |
| Total  NSP-Minnesota long-term debt                                                                                 |       | $                          | 1,859,737  |   | $ | 1,940,958 |   |
|                                                                                                                |       |                       |       |   |   |
| **Common  Stockholder’s Equity**                                                                               |       |                       |       |   |   |
| Common stock  — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000  shares in 2004 and 2003 |       | $                          | 10         |   | $ | 10 |   |
| Capital in  excess of par value on common stock                                                                     |       | 1,023,377                  |       | 842,969 |   |
| Retained  earnings                                                                                                  |       | 983,940                    |       | 965,880 |   |
| Accumulated  other comprehensive loss                                                                               |       | —                     |       | (4 | ) |
| Total common  stockholder’s equity                                                                             |       | $                          | 2,007,327  |   | $ | 1,808,855 |   |

 

----

(a)      Resource recovery financing

 

(b)      Pollution control financing

 

See Notes to Consolidated Financial Statements

 

36

----

 

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1. Summaryof Significant Accounting Policies**

 

***Business and System of Accounts*****— NSP-Minnesota is engaged principally in thegeneration, purchase, transmission, distribution and sale of electricity and inthe purchase, transportation, distribution and sale of natural gas.NSP-Minnesota is subject to the regulatory provisions of the PUHCA. NSP-Minnesotais also subject to regulation by the FERC and state utility commissions. All ofNSP-Minnesota’s accounting records conform to the FERC uniform system ofaccounts or to systems required by various state regulatory commissions, whichare the same in all material aspects.

 

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

 

***Revenue Recognition*****—Revenues related to the sale of energy are generally recorded when service isrendered or energy is delivered to customers. However, the determination of theenergy sales to individual customers is based on the reading of their meter,which occurs on a systematic basis throughout the month. At the end of eachmonth, amounts of energy delivered to customers since the date of the lastmeter reading are estimated and the corresponding unbilled revenue isestimated.

 

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

 

•             NSP-Minnesota’s rates include a cost-of-fueland energy and a cost-of-gas recovery mechanism allowing dollar-for-dollarrecovery of the respective costs, which are trued-up on a two-month and annualbasis, respectively.

 

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

 

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

 

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

 

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

 

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

 

***Property, Plant, Equipment and Depreciation*****— Property, plant and equipment is stated atoriginal cost. The cost of plant includes direct labor and materials,contracted work, overhead costs and applicable interest expense. The cost ofplant retired is charged to accumulated depreciation and amortization. Removalcosts associated with non-legal obligations are reclassified from accumulateddepreciation and reflected as regulatory liabilities. Significant additions orimprovements extending asset lives are capitalized, while repairs andmaintenance are charged to expense as incurred. Maintenance and replacement ofitems determined to be less than units of property are charged to operatingexpenses. Property, plant and equipment also include costs associated with theengineering design of future generating stations and other property held forfuture use.

 

37

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NSP-Minnesota determines thedepreciation of its plant by using the straight-line method, which spreads theoriginal cost equally over the plant’s useful life. Depreciation expense forNSP-Minnesota, expressed as a percentage of average depreciable property, forthe years ended Dec. 31, 2004, 2003 and 2002 was 3.8 percent, 3.5 percent and3.7 percent, respectively.

 

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

 

***Decommissioning*****—NSP-Minnesota accounts for the future cost of decommissioning, or retirement,of its nuclear generating plants through annual depreciation accruals using anannuity approach designed to provide for full rate recovery of the futuredecommissioning costs. The decommissioning calculation covers all expenses,including decontamination and removal of radioactive material, and extends overthe estimated lives of the plants. The calculation assumes that NSP-Minnesotawill recover those costs through rates. The fair value of external nucleardecommissioning fund investments are estimated based on quoted market pricesfor those or similar investments. Unrealized gains or losses on the fund’sassets are deferred as regulatory assets or liabilities. For more informationon nuclear decommissioning, see Note 12 to the Consolidated FinancialStatements.

 

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

 

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

 

Estimated remediation costs,excluding inflationary increases, are recorded. The estimates are based onexperience, an assessment of the current situation and the technology currentlyavailable for use in the remediation. The recorded costs are regularly adjustedas estimates are revised and remediation proceeds. If several designatedresponsible parties exist, costs are estimated and recorded only for theutility subsidiary share of the cost. Any future costs of restoring sites whereoperation may extend indefinitely are treated as a capitalized cost of plantretirement. The depreciation expense levels recoverable in rates include aprovision for removal expenses, which has the latitude to compensate for finalremediation costs. Removal costs recovered in rates are classified as aregulatory liability.

 

***Legal Costs***— Litigation settlements are recorded when it is probable NSP-Minnesota isliable for the costs and the liability can be reasonably estimated.  Legal accruals are recorded net of insurancerecovery.  Legal costs related tosettlements are not accrued, but expensed as incurred.

 

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

 

Due to the effects of pastregulatory practices, when deferred taxes were not required to be recorded, thereversal of some temporary differences was accounted for as current income taxexpense. Investment tax credits are deferred and their benefits spread over theestimated lives of the related property. Utility rate regulation also hascreated certain regulatory assets and liabilities related to income taxes,which are summarized in Note 13 to the Consolidated Financial Statements. Formore information on income taxes, see Note 8

 

38

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to the ConsolidatedFinancial Statements.

 

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

 

***Cash and Cash Equivalents*****— NSP-Minnesota considers investments with aremaining maturity of three months or less at the time of purchase to be cashequivalents. Those instruments are primarily commercial paper and money marketfunds. Restricted cash is classified as a current asset as all restricted cashis designated for interest and principal payments due within one year.

 

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

 

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

 

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

 

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

 

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

 

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

 

***Deferred Financing Costs*****— Other assets include deferred financingcosts, which were amortized over the remaining maturity periods of the relateddebt. NSP-Minnesota’s deferred financing costs, net of amortization at Dec. 31,2004, 2003 and 2002 are $15.8 million, $17.4 million and $21.1 million,respectively.

 

***Reclassifications*****—Certain items in the 2002 and 2003 statements of income and the 2003 balancesheet have been reclassified to conform to 2004 presentation. Thesereclassifications had no effect on net income.

 

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

 

***Credit Facilities***— At Dec. 31, 2004, NSP-Minnesota had the following credit facility ineffect, in millions of dollars.  Asyndicate of lending banks supports the credit facility in exchange for anegotiated commitment fee.

 
| **Maturity** | ** ** | **Term** | ** ** | **Credit Line** | ** ** | **Credit Line  Available** | ** ** |
|--------------|------------|----------|------------|-----------------|------------|----------------------------|------------|
| May 2005     |       | 364 days |       | $               | 300        |                       | $          | 171 |   |
|              |            |          |            |                 |            |                            |            |  |  |

 

NSP-Minnesota’s creditfacility is expected to be renewed as a five-year revolving credit facilityprior to May 2005 for which borrowings will be classified as a long-termliability on the consolidated balance sheet.

 

The line of credit providesshort-term financing in the form of notes payable to banks, letters of credit,and, depending on credit ratings, provide support for commercial paperborrowings. The borrowing rate under the line of credit is based on either thebank’s prime rate or the applicable London Interbank Offered Rate (LIBOR) plusa borrowing margin.

 

39

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At Dec. 31, 2004 and 2003,NSP-Minnesota had $90 million and $58 million, respectively, in notes payableto banks, which were drawn on the line of credit.  The weighted average interest rate at Dec.31, 2004 was 5.25 percent.  Also, $39.4million of letters of credit were outstanding at Dec. 31, 2004, as discussed inNote 10 to the Consolidated Financial Statements, of which approximately $38.6million were outstanding under the credit facility, which further reducedamounts available under the line.

 

***Money Pool***-In 2003, Xcel Energy established a money pool arrangement with the utilitysubsidiaries, subject to receipt of required state regulatory approvals.  NSP-Minnesota received approval toparticipate in the money pool arrangement in 2004.  The money pool allows for short-term loansbetween the utility subsidiaries and from the holding company to the utilitysubsidiaries at market-based interest rates. The money pool arrangement doesnot allow loans from the utility subsidiaries to the holding company.NSP-Minnesota has approval to borrow up to $250 million under thearrangement.  NSP-Minnesota had noborrowings or loans outstanding under the arrangement at Dec. 31, 2004.

 

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

 

Except for minor exclusions,all property of NSP-Minnesota is subject to the lien of its first mortgage indenture,which is a contract between NSP-Minnesota and its bondholders.

 

NSP-Minnesota’s firstmortgage bond indenture provides for the ability to have sinking fundrequirements. Such sinking fund obligations may be satisfied with propertyadditions or cash. At Dec. 31, 2004, NSP-Minnesota has no sinking fundrequirements for current bonds outstanding.

 

NSP-Minnesota’s firstmortgage indenture places certain restrictions on the amount of cash dividendsit can pay Xcel Energy, the holder of its common stock. Even with theserestrictions, NSP-Minnesota could have paid more than $833 million inadditional cash dividends on common stock at Dec. 31, 2004.

 

To facilitate its potentialdebt issuances, NSP-Minnesota may file a long-term debt shelf registration statementwith the SEC for up to $1 billion in 2005.

 

Maturities of long-term debtare listed in the following table, in millions of dollars:

 
| 2005 |   | $   | 82     |   |
|------|--------|-----|--------|--------|
| 2006 |   | 205 |   |
| 2007 |   | 3   |   |
| 2008 |   | 3   |   |
| 2009 |   | 250 |   |

 

**4.Mandatorily Redeemable Preferred Securities of Subsidiary Trusts**

 

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

 

Distributions paid topreferred security holders are reflected as a financing cost in theaccompanying Consolidated Statements of Income along with interest expense.

 

**5. JointPlant Ownership**

 

Following are theinvestments by NSP-Minnesota in jointly owned plants and the related ownershippercentages as of Dec. 31, 2004:

 

| ** **                                      | ** ** | **Plant in  Service**      | ** ** | **Accumulated  Depreciation** | ** ** | **Construction  Work in  Progress** | ** ** | **Ownership%** | ** ** |
|-------------------------------------------------|------------|----------------------------|------------|-------------------------------|------------|-------------------------------------|------------|----------------|------------|
| ** **                                      | ** ** | **(Thousands of dollars)** | ** ** |
| ** **                                      | ** ** | ** **                 | ** ** | ** **                    | ** ** | ** **                          | ** ** | ** **     | ** ** |
| NSP-Minnesota:                                  |       |                       |       |                          |       |                                |       |           |       |
| Sherco Unit  3                                  |       | $                          | 492,581    |                          | $          | 268,734                             |       | $              | 2,244      |   | 59.0 |   |
| Sherco  Common Facilities Units 1, 2 & 3    |       | 102,556                    |       | 50,428                        |       | —                              |       | 65.6           |       |
| Transmission  facilities, including substations |       | 4,832                      |       | 1,765                         |       | —                              |       | 59.0           |       |
| Total  NSP-Minnesota                            |       | $                          | 599,969    |                          | $          | 320,927                             |       | $              | 2,244      |   |   |   |

 

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NSP-Minnesota is part ownerof Sherco 3, an 860-megawatt, coal-fueled electric generating unit.NSP-Minnesota is the operating agent under the joint ownership agreement.NSP-Minnesota’s share of operating expenses and construction expenditures areincluded in the applicable utility components of operating expenses. Each ofthe respective owners is responsible for the issuance of its own securities tofinance its portion of the construction costs.

 

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

 

Total income tax expensefrom operations differs from the amount computed by applying the statutoryfederal income tax rate to income before income tax expense. The reasons forthe difference at Dec. 31 are:

 
| ** **                                             | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|--------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Federal  statutory rate                                |       | 35.0       | %          | 35.0       | %          | 35.0       | %          |
| Increases  (decreases) in tax from:                    |       |       |       |       |       |       |       |
| State income  taxes, net of federal income tax benefit |       | 4.2        | %          | 3.6        | %          | 5.6        | %          |
| Life  insurance policies                               |       | (0.3       | )%         | (0.4       | )%         | (0.3       | )%         |
| Tax credits  recognized                                |       | (2.9       | )%         | (3.0       | )%         | (3.8       | )%         |
| Regulatory  differences — utility plant items     |       | (2.2       | )%         | (1.2       | )%         | (0.3       | )%         |
| Resolution  of income tax audits                       |       | (3.8       | )%         | (5.1       | )%         | —     |       |
| Other — net                                       |       | (0.9       | )%         | (0.5       | )%         | (1.1       | )%         |
| Effective  income tax rate                             |       | 29.1       | %          | 28.4       | %          | 35.1       | %          |

 

Income taxes comprise thefollowing expense (benefit) items:

 

| ** **                              | ** ** | **2004**                   | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------|------------|----------------------------|------------|----------|------------|----------|------------|
| ** **                              | ** ** | **(Thousands of dollars)** | ** ** |
| Current  federal tax expense            |       | $                          | 53,693     |     | $          | 74,954   |       | $ | 114,221 |   |
| Current  state tax expense              |       | 29,826                     |       | 8,013    |       | 31,740   |       |
| Current  federal tax credits            |       | (2,301                     | )          | (639     | )          | (636     | )          |
| Deferred  federal tax expense (benefit) |       | 25,739                     |       | 5,212    |       | (20,972  | )          |
| Deferred  state tax expense (benefit)   |       | (5,194                     | )          | (3,651   | )          | (5,308   | )          |
| Deferred  investment tax credits        |       | (7,150                     | )          | (7,365   | )          | (10,904  | )          |
| Total income  tax expense               |       | $                          | 94,613     |     | $          | 76,524   |       | $ | 108,141 |   |

 

The components of deferredincome tax at Dec. 31 were:

 
| ** **                                                                                              | ** ** | **2004**                   | ** ** | **2003** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|----------------------------|------------|----------|------------|
| ** **                                                                                              | ** ** | **(Thousands of dollars)** | ** ** |
| Deferred tax  expense excluding items below                                                             |       | $                          | 53,280     |     | $          | 44,242 |   |
| Amortization  and adjustments to deferred income taxes on income tax regulatory assets and  liabilities |       | (32,732                    | )          | (42,677  | )          |
| Tax expense  allocated to other comprehensive income and other                                          |       | (3                         | )          | (4       | )          |
| Deferred tax  expense                                                                                   |       | $                          | 20,545     |     | $          | 1,561 |   |
|                                                                                                         |            |                            |            |          |            |  |  |  |  |

 

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

 

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| ** **                                          | ** ** | **2004**                   | ** ** | **2003**   | ** ** |
|-----------------------------------------------------|------------|----------------------------|------------|------------|------------|
| ** **                                          | ** ** | **(Thousands of dollars)** | ** ** |
| ** **                                          | ** ** | ** **                 | ** ** | ** ** | ** ** |
| Deferred tax  liabilities:                          |       |                       |       |       |       |
| Differences  between book and tax bases of property |       | $                          | 730,792    |       | $          | 677,359 |   |
| Regulatory  assets                                  |       | 165,157                    |       | 152,101    |       |
| Other                                               |       | 14,723                     |       | 10,213     |       |
| Total  deferred tax liabilities                     |       | $                          | 910,672    |       | $          | 839,673 |   |
|                                                |       |                       |       |       |       |
| Deferred tax  assets:                               |       |                       |       |       |       |
| Regulatory  liabilities                             |       | $                          | 20,903     |       | $          | 22,482 |   |
| Employee  benefits                                  |       | 47,417                     |       | 33,177     |       |
| Deferred  investment tax credits                    |       | 24,069                     |       | 27,050     |       |
| Tax credit  carryforward                            |       | 2,965                      |       | —     |       |
| Other                                               |       | 21,727                     |       | 16,652     |       |
| Total  deferred tax assets                          |       | $                          | 117,081    |       | $          | 99,361 |   |
| Net deferred  tax liability                         |       | $                          | 793,591    |       | $          | 740,312 |   |
|                                                     |            |                            |            |            |            |  |  |  |  |

 

**7. BenefitPlans and Other Postretirement Benefits**

 

Xcel Energy offers variousbenefit plans to its benefit employees, including those of NSP-Minnesota.  Approximately 51 percent of benefit employeesare represented by several local labor unions under severalcollective-bargaining agreements. At Dec. 31, 2004, NSP-Minnesota had 2,197bargaining employees covered under a collective-bargaining agreement, whichexpires at the end of 2007.

 

**PensionBenefits**

 

Xcel Energy has severalnoncontributory, defined benefit pension plans that cover almost all employees,including those of NSP-Minnesota. Benefits are based on a combination of years of service, the employee’saverage pay and Social Security benefits.

 

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

 

***Pension Plan Assets***— Plan assets principally consist of the common stock of publiccompanies, corporate bonds and U.S. government securities. In 2004, Xcel Energycompleted a review of its pension plan asset allocation and adopted revisedasset allocation targets.  The targetrange for our pension asset allocation is 60 percent in equity investments, 20percent in fixed income investments, no cash investments and 20 percent innontraditional investments, such as real estate, timber ventures, privateequity and a diversified commodities index.

 

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

 

| ** **                  | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|-----------------------------|------------|------------|------------|------------|------------|
| ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Equity  securities          |       | 69         | %          | 75         | %          |
| Debt  securities            |       | 19         |       | 14         |       |
| Real estate                 |       | 4          |       | 3          |       |
| Cash                        |       | 1          |       | —     |       |
| Nontraditional  investments |       | 7          |       | 8          |       |
|                        |       | 100        | %          | 100        | %          |

 

During 2003, Xcel Energyentered into a number of hedging arrangements within the pension trust designedto provide protection from a loss of asset value in the event of a broaddecline in equity prices. These arrangements were closed out in December 2004.

 

Xcel Energy bases itsinvestment return assumption on expected long-term performance for each of theinvestment types included in its pension asset portfolio. Xcel Energy considersthe actual historical returns achieved by its asset portfolio over the past20-year or longer period, as well as the long-term return levels projected andrecommended by investment experts. The historical weighted average annualreturn for the past 20 years for the Xcel Energy portfolio of pensioninvestments is 12.8 percent, which is in excess of the current assumptionlevel. The pension cost determinations assume the continued current mix ofinvestment types over the long-term. The Xcel Energy portfolio is heavilyweighted toward equity securities, includes nontraditional investments that canprovide a

 

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higher-than-average return.As is the experience in recent years, a higher weighting in equity investmentscan increase the volatility in the return levels actually achieved by pensionassets in any year. Investment returns in 2002 were below the assumed level of9.5 percent, but in 2003 investment returns exceeded the assumed level of 9.25percent and in 2004 investment returns exceeded the assumed level of 9.0percent. Xcel Energy continually reviews its pension assumptions. For 2005,Xcel Energy has changed the investment return assumption to 8.75 percent toreflect its current expectations of investment returns.

 

***Benefit Obligations***— A comparison of the actuarially computed pension benefit obligationand plan assets, on a combined basis, is presented in the following table:

 

| **(Thousands of dollars)**                                       | ** ** | **2004**       | ** ** | **2003**       | ** ** |
|------------------------------------------------------------------|------------|----------------|------------|----------------|------------|
| ** **                                                       | ** ** | ** **     | ** ** | ** **     | ** ** |
| **Accumulated  Benefit Obligation at Dec. 31**                   |       | $              | 2,575,317  |           | $          | 2,512,138 |   |
|                                                             |       |           |       |           |       |
| **Change  in Projected Benefit Obligation**                      |       |           |       |           |       |
| Obligation  at Jan. 1                                            |       | $              | 2,632,491  |           | $          | 2,505,576 |   |
| Service cost                                                     |       | 58,150         |       | 67,449         |       |
| Interest  cost                                                   |       | 165,361        |       | 170,731        |       |
| Plan  amendments                                                 |       | —         |       | 85,937         |       |
| Actuarial  loss                                                  |       | 133,552        |       | 82,197         |       |
| Settlements                                                      |       | (27,627        | )          | (9,546         | )          |
| Curtailment  gain                                                |       | —         |       | (26,407        | )          |
| Benefit  payments                                                |       | (229,664       | )          | (243,446       | )          |
| Obligation  at Dec. 31                                           |       | $              | 2,732,263  |           | $          | 2,632,491 |   |
| ** **                                                       | ** ** | ** **     | ** ** | ** **     | ** ** |
| **Change  in Fair Value of Plan Assets**                         |       |           |       |           |       |
| Fair value  of plan assets at Jan. 1                             |       | $              | 3,024,661  |           | $          | 2,639,963 |   |
| Actual  return on plan assets                                    |       | 284,600        |       | 605,978        |       |
| Employer  contributions                                          |       | 10,046         |       | 31,712         |       |
| Settlements                                                      |       | (27,627        | )          | (9,546         | )          |
| Benefit  payments                                                |       | (229,664       | )          | (243,446       | )          |
| Fair value  of plan assets at Dec. 31                            |       | $              | 3,062,016  |           | $          | 3,024,661 |   |
|                                                             |       |           |       |           |       |
| **Funded  Status of Plans at Dec. 31**                           |       |           |       |           |       |
| Net asset                                                        |       | $              | 329,753    |           | $          | 392,170 |   |
| Unrecognized  transition asset                                   |       | —         |       | (7             | )          |
| Unrecognized  prior service cost                                 |       | 244,437        |       | 273,725        |       |
| Unrecognized  loss                                               |       | 176,957        |       | 9,710          |       |
| Xcel Energy  net pension amounts recognized on balance sheet     |       | $              | 751,147    |           | $          | 675,598 |   |
|                                                             |       |           |       |           |       |
| NSP-Minnesota  prepaid pension asset recorded                    |       | $              | 361,446    |           | $          | 317,956 |   |
|                                                             |       |           |       |           |       |
| **Measurement  Date**                                            |       | Dec. 31,  2004 |       | Dec. 31,  2003 |       |
|                                                             |       |           |       |           |       |
| **Significant  Assumptions Used to Measure Benefit Obligations** |       |           |       |           |       |
| Discount  rate for year-end valuation                            |       | 6.00           | %          | 6.25           | %          |
| Expected  average long-term increase in compensation level       |       | 3.50           | %          | 3.50           | %          |
|                                                                  |            |                |            |                |            |  |  |  |  |  |  |

 

***Cash Flows***—Cash funding requirements can be impacted by changes to actuarial assumptions,actual asset levels and other pertinent calculations prescribed by the fundingrequirements of income tax and other pension-related regulations. Theseregulations did not require cash funding in the years 2002 through 2004 forXcel Energy’s pension plans and is not expected to require cash funding in2005.

 

***Benefit Costs***—******Thecomponents of net periodic pension cost (credit) are:

 

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| **(Thousands of dollars)**                                    | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|---------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                  |       | $          | 58,150     |       | $          | 67,449     |       | $ | 65,649 |   |
| Interest  cost                                                |       | 165,361    |       | 170,731    |       | 172,377    |       |
| Expected  return on plan assets                               |       | (302,958   | )          | (322,011   | )          | (339,932   | )          |
| Curtailment  (gain) loss                                      |       | —     |       | (17,363    | )          | —     |       |
| Settlement  (gain) loss                                       |       | (926       | )          | (1,135     | )          | —     |       |
| Amortization  of transition asset                             |       | (7         | )          | (1,996     | )          | (7,314     | )          |
| Amortization  of prior service cost                           |       | 30,009     |       | 28,230     |       | 22,663     |       |
| Amortization  of net gain                                     |       | (15,207    | )          | (44,825    | )          | (69,264    | )          |
| Net periodic  pension cost (credit) under SFAS No. 87         |       | $          | (65,578    | )          | $          | (120,920   | )          | $ | (155,821 | ) |
|                                                          |       |       |       |       |       |       |       |
| **NSP-Minnesota**                                             |       |       |       |       |       |       |       |
| Net periodic  pension credit                                  |       | $          | (43,490    | )          | $          | (54,243    | )          | $ | (71,928 | ) |
| Credits not  recognized due to effects of regulation          |       | 38,967     |       | 51,311     |       | 71,928     |       |
| Net benefit  cost (credit) recognized for financial reporting |       | $          | (4,523     | )          | $          | (2,932     | )          | — |   |
|                                                          |       |       |       |       |       |       |       |
| **Significant  Assumptions Used to Measure Costs**            |       |       |       |       |       |       |       |
| Discount  rate                                                |       | 6.25       | %          | 6.75       | %          | 7.25       | %          |
| Expected  average long-term increase in compensation level    |       | 3.50       | %          | 4.00       | %          | 4.50       | %          |
| Expected  average long-term rate of return on assets          |       | 9.00       | %          | 9.25       | %          | 9.50       | %          |
|                                                               |            |            |            |            |            |            |            |  |  |  |  |  |  |  |

 

Pension costs include anexpected return impact for the current year that may differ from actualinvestment performance in the plan. The return assumption used for 2005 pensioncost calculations will be 8.75 percent. The cost calculation uses amarket-related valuation of pension assets, which reduces year-to-yearvolatility by recognizing the differences between assumed and actual investmentreturns over a five-year period.

 

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

 

**DefinedContribution Plans**

 

Xcel Energy maintains 401(k)and other defined contribution plans that cover substantially all employees.The contributions for NSP-Minnesota were approximately $3.8 million in 2004,$3.2 million in 2003, and $3.1 million in 2002.

 

Until May 6, 2002, XcelEnergy had a leveraged employee stock ownership plan (ESOP) that coveredsubstantially all employees of NSP-Minnesota and NSP-Wisconsin. Xcel Energymade contributions to this noncontributory, defined contribution plan to theextent it realized tax savings from dividends paid on certain ESOP shares. ESOPcontributions had no material effect on Xcel Energy earnings because thecontributions were essentially offset by the tax savings provided by thedividends paid on ESOP shares. Xcel Energy allocated leveraged ESOP shares toparticipants when it repaid ESOP loans with dividends on stock held by theESOP.

 

In May 2002, the ESOP wasterminated and its assets were combined into the Xcel Energy retirement savings401(k) plan. Starting with the 2003 plan year, the ESOP component of the 401(k)plan is no longer leveraged.

 

Xcel Energy’s leveraged ESOPheld 10.7 million shares of Xcel Energy common stock at May 6, 2002. XcelEnergy excluded an average of 0.7 million uncommitted leveraged ESOP sharesfrom 2002 earnings-per-share-calculations. On Nov. 19, 2002, Xcel Energy paidoff all of the ESOP loans. All uncommitted ESOP shares were released and wereused by Xcel Energy for the 2002 employer matching contribution to its 401(k)plan.

 

**PostretirementHealth Care Benefits**

 

Xcel Energy has acontributory health and welfare benefit plan that provides health care anddeath benefits to most Xcel Energy retirees. The former NSP discontinuedcontributing toward health care benefits for nonbargaining employees retiringafter 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin whoretired after 1999. Employees of the former NCE who retired in 2002 continue toreceive employer-subsidized health care benefits. Employees of the former NSPwho retired after 1998 are eligible to participate in the Xcel Energy healthcare program with no employer subsidy.

 

In conjunction with the 1993adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement BenefitsOther Than Pensions,”

 

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Xcel Energy elected to amortizethe unrecognized accumulated postretirement benefit obligation (APBO) on astraight-line basis over 20 years.

 

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

 

***Plan Assets***—Certain state agencies that regulate Xcel Energy’s utility subsidiaries also haveissued guidelines related to the funding of SFAS No. 106 costs. In 2004, theinvestment strategy for the union asset fund was changed to increase theexposure to equity funds. Also, a portion of the assets contributed on behalfof non-bargaining retirees has been funded into a sub-account of the XcelEnergy pension plans. These assets are invested in a manner consistent with theinvestment strategy for the pension plan.

 

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

 

| ** **                     | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|--------------------------------|------------|------------|------------|------------|------------|
| ** **                     | ** ** | ** ** | ** ** | ** ** | ** ** |
| Fixed  income/debt securities  |       | 21         | %          | 2          | %          |
| Equity  mutual fund securities |       | 54         |       | 14         |       |
| Cash  equivalents              |       | 25         |       | 84         |       |
|                           |       | 100%       |       | 100        | %          |

 

Xcel Energy bases itsinvestment return assumption for the postretirement health care fund assets onexpected long-term performance for each of the investment types included in itspostretirement health care asset portfolio. Given the fairly short time periodin which funding has been required, Xcel Energy does not consider the actualhistorical returns achieved by its postretirement health care fund assetportfolio to be significant in establishing long-term return assumptions.Instead, Xcel Energy considers the long-term return levels projected andrecommended by investment experts, weighted for the target mix of assetcategories in our portfolio, and does not consider investment return volatilityto be a material factor in postretirement health care costs.

 

***Benefit Obligations***— A comparison of the actuarially computed benefit obligation and planassets for Xcel Energy postretirement health care plans that benefit employeesof its utility subsidiaries is presented in the following table:

 

 

| **(Thousands of dollars)**                                                       | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|----------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                                                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Change  in Benefit Obligation**                                                |       |       |       |       |       |
| Obligation  at Jan. 1                                                            |       | $          | 775,230    |       | $          | 767,975 |   |
| Service cost                                                                     |       | 6,100      |       | 5,893      |       |
| Interest  cost                                                                   |       | 52,604     |       | 52,426     |       |
| Acquisitions/(divestitures)                                                      |       | —     |       | (31,584    | )          |
| Plan  amendments                                                                 |       | (1,600     | )          | (33,304    | )          |
| Plan  participants’ contributions                                           |       | 9,532      |       | 16,577     |       |
| Actuarial  loss                                                                  |       | 148,341    |       | 122,864    |       |
| Curtailments                                                                     |       | —     |       | (249       | )          |
| Benefit  payments                                                                |       | (61,082    | )          | (60,754    | )          |
| Impact of  Medicare Prescription Drug, Improvement and Modernization Act of 2003 |       | —     |       | (64,614    | )          |
| Obligation  at Dec. 31                                                           |       | $          | 929,125    |       | $          | 775,230 |   |
|                                                                             |       |       |       |       |       |
| **Change  in Fair Value of Plan Assets**                                         |       |       |       |       |       |
| Fair value of  plan assets at Jan. 1                                             |       | $          | 285,861    |       | $          | 250,983 |   |
| Actual  return on plan assets                                                    |       | 21,950     |       | 11,045     |       |
| Plan  participants’ contributions                                           |       | 9,532      |       | 16,577     |       |
| Employer  contributions                                                          |       | 62,406     |       | 68,010     |       |
| Benefit  payments                                                                |       | (61,082    | )          | (60,754    | )          |
| Fair value  of plan assets at Dec. 31                                            |       | $          | 318,667    |       | $          | 285,861 |   |
|                                                                             |       |       |       |       |       |
| **Funded  Status at Dec. 31**                                                    |       |       |       |       |       |
| Net  obligation                                                                  |       | $          | 610,458    |       | $          | 489,369 |   |
| Unrecognized  transition asset (obligation)                                      |       | (117,600   | )          | (133,778   | )          |
| Unrecognized  prior service cost                                                 |       | 17,914     |       | 20,093     |       |
| Unrecognized  gain (loss)                                                        |       | (383,026   | )          | (255,174   | )          |
| Accrued  benefit liability recorded                                              |       | $          | 127,746    |       | $          | 120,510 |   |
|                                                                             |       |       |       |       |       |
| NSP-Minnesota  accrued benefit liability recorded                                |       | $          | 54,801     |       | $          | 53,942 |   |
| ** **                                                                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Significant  Assumptions Used to Measure Benefit Obligations**                 |       |       |       |       |       |
| Discount  rate for year-end valuation                                            |       | 6.00       | %          | 6.25       | %          |
|                                                                                  |            |            |            |            |            |  |  |  |

 

45

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Effective Dec. 31, 2004,Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0percent and lowered the ultimate trend assumption from 5.5 percent to 5.0percent.  The period until the ultimaterate is reached was also increased from two years to six years.  This trend assumption was used to value the actuarialbenefit obligations at year-end 2004, and will be used in 2005 retiree medicalcost determinations.  Xcel Energy basesits medical trend assumption on the long-term cost inflation expected in thehealth care market, considering the levels projected and recommended byindustry experts, as well as recent actual medical cost increases experiencedby Xcel Energy’s retiree medical plan.

 

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

 
| **(Millions of dollars)**                                                       | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------|------------|------------|------------|
|                                                                            |       |       |       |
| 1-percent  increase in APBO components at Dec. 31, 2004                         |       | $          | 23.8       |   |
| 1-percent  decrease in APBO components at Dec. 31, 2004                         |       | (19.7      | )          |
| 1-percent  increase in service and interest components of the net periodic cost |       | 1.6        |       |
| 1-percent  decrease in service and interest components of the net periodic cost |       | (1.3       | )          |
|                                                                                 |            |            |            |  |

 

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

 

***Cash Flows***—The postretirement health care plans have no funding requirements under incometax and other retirement-related regulations other than fulfilling benefitpayment obligations, when claims are presented and approved under the plans.Additional cash funding requirements are prescribed by certain state andfederal rate regulatory authorities, as discussed previously. Xcel Energy expectsto contribute approximately $73 million during 2005.

 

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

 

| **(Thousands of dollars)**                                               | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|--------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                             |       | $          | 6,100      |       | $          | 5,893      |       | $ | 5,967 |   |
| Interest  cost                                                           |       | 52,604     |       | 52,426     |       | 48,304     |       |
| Expected  return on plan assets                                          |       | (23,066    | )          | (22,185    | )          | (21,011    | )          |
| Curtailment  (gain) loss                                                 |       | —     |       | (2,128     | )          | —     |       |
| Settlement  (gain) loss                                                  |       | —     |       | (916       | )          | —     |       |
| Amortization  of transition obligation                                   |       | 14,578     |       | 15,426     |       | 16,771     |       |
| Amortization  of prior service cost (credit)                             |       | (2,179     | )          | (1,533     | )          | (1,130     | )          |
| Amortization  of net loss (gain)                                         |       | 21,651     |       | 15,409     |       | 5,380      |       |
| Net periodic  postretirement benefit cost (credit) under SFAS No. 106    |       | $          | 69,688     |       | $          | 62,392     |       | $ | 54,281 |   |
|                                                                     |       |       |       |       |       |       |       |
| **NSP-Minnesota**                                                        |       |       |       |       |       |       |       |
| Net periodic  postretirement benefit cost recognized – SFAS No. 106 |       | $          | 15,936     |       | $          | 16,897     |       | $ | 12,667 |   |
|                                                                     |       |       |       |       |       |       |       |
| **Significant  assumptions used to measure costs (income)**              |       |       |       |       |       |       |       |
| Discount  rate                                                           |       | 6.25       | %          | 6.75       | %          | 7.25       | %          |
| Expected  average long-term rate of return on assets (before tax)        |       | 5.5 - 8.5  | %          | 8.0 - 9.0  | %          | 9.0        | %          |

 

***Impact of 2003 Medicare Legislation***— On Dec. 8, 2003, President Bush signed intolaw the Medicare Prescription Drug,

 

46

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Improvement and ModernizationAct of 2003 (the Act). The Act expanded Medicare to include, for the firsttime, coverage for prescription drugs. This new coverage is generally effectiveJan. 1, 2006. Many of Xcel Energy’s retiree medical programs provideprescription drug coverage for retirees over age 65 with coverage at leastequivalent to the benefit to be provided under Medicare. While retirees remainin Xcel Energy’s postretirement health care plan without participating in thenew Medicare prescription drug coverage, Medicare will share the cost of XcelEnergy’s plan. This legislation has therefore reduced Xcel Energy’s share ofthe obligation for future retiree medical benefits.

 

As of Dec. 31,2003, Xcel Energy had reduced the postretirement health care benefit obligationby $64.6 million due to the expected sharing of the cost of the program byMedicare under the new legislation. Also, beginning in 2004, the annual net periodic postretirement benefitcost was reduced by approximately $10 million as a result of the expected sharingof the cost of the program by Medicare, with similar savings expected insubsequent years.  These estimatedreductions do not reflect any changes that may result in future levels ofparticipation in the plan or the associated per capita claims cost due to theavailability of prescription drug coverage for Medicare-eligible retirees.Also, in reflecting this legislation, Medicare cost sharing for a plan has beenassumed only if Xcel Energy’s projected contribution to the plan is expected tobe at least equal to the Medicare Part D basic benefit.

 

# **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** | ** ** |
|----------------------------|------------|-----------------------------------------|------------|--------------------------------------------------------------------|------------|-----------------------------------------|------------|------------------------------------------------------------------|------------|
| 2005                       |       | $                                       | 199,117    |                                                               | $          | 59,642                                  |       | $                                                                | —     |   | $ | 59,642 |   |
| 2006                       |       | 211,830                                 |       | 61,652                                                             |       | 4,297                                   |       | 57,355                                                           |       |
| 2007                       |       | 217,582                                 |       | 63,640                                                             |       | 4,591                                   |       | 59,049                                                           |       |
| 2008                       |       | 225,050                                 |       | 65,393                                                             |       | 4,821                                   |       | 60,572                                                           |       |
| 2009                       |       | 231,704                                 |       | 67,036                                                             |       | 5,008                                   |       | 62,028                                                           |       |
| 2010-2014                  |       | 1,202,161                               |       | 352,308                                                            |       | 27,192                                  |       | 325,116                                                          |       |
|                            |            |                                         |            |                                                                    |            |                                         |            |                                                                  |            |  |  |  |  |

 

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

 

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

 
| **(Thousands of dollars)**                                                                         | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|----------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest  income                                                                                   |       | $          | 8,681      |       | $          | 7,745      |       | $ | 19,215 |   |
| Other  nonoperating income                                                                         |       | 557        |       | 193        |       | 2,163      |       |
| Gain (Loss) on  disposal of assets                                                                 |       | (1,888     | )          | (1,125     | )          | 4,764      |       |
| Interest  expense on corporate-owned life insurance and other employee-related  insurance policies |       | (6,261     | )          | (6,622     | )          | (6,181     | )          |
| Other  nonoperating expense                                                                        |       | —     |       | (2,991     | )          | (383       | )          |
| Total  interest and other income, net of nonoperating expenses                                     |       | $          | 1,089      |       | $          | (2,800     | )          | $ | 19,578 |   |
|                                                                                                    |            |            |            |            |            |            |            |  |  |  |  |

 

**9.Derivative Instruments**

 

In the normal course of business, NSP-Minnesota is exposed to a varietyof market risks.  Market risk is thepotential loss that may occur as a result of changes in the market or fairvalue of a particular instrument or commodity. NSP-Minnesota utilizes, in accordance with approved risk managementpolicies, a variety of derivative instruments to mitigate market risk and to enhanceour operations.  The use of these derivativeinstruments is discussed in further detail below.

 

***Utility CommodityPrice Risk —***NSP-Minnesota is exposed to commodity price risk in their generation and retaildistribution operations.  Commodity pricerisk is managed by entering into both long- and short-term physical purchaseand sales contracts for electric power, natural gas, coal and fuel oil.  Commodity risk also is managed through theuse of financial derivative instruments. NSP-Minnesota utilizes these derivative instruments to reduce thevolatility in the cost of commodities acquired on behalf of our retailcustomers even though regulatory jurisdiction may provide for adollar-for-dollar recovery of actual costs. In these instances, the use

 

47

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ofderivative instruments is done consistently with the local jurisdictional costrecovery mechanism.  NSP-Minnesota’s riskmanagement policy allows it to manage market price risk to the extent suchexposure exists.

 

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

 

# **Types of and Accounting for Derivative Instruments**

# ** **

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

 

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

 

Hedge effectiveness is recorded based on the nature of the item beinghedged.  Hedging transactions for thesales of electric energy are recorded as a component of revenue, hedgingtransactions for fuel used in energy generation are recorded as a component offuel costs and hedging transactions for natural gas purchased for resale arerecorded as a component of natural gas costs. NSP-Minnesota is allowed to recover in natural gas rates the costs ofcertain financial instruments acquired to reduce commodity cost volatility.

 

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

 

# **Cash Flow Hedges**

# ** **

The effectiveportion of the change in the fair value of a derivative instrument qualifyingas a cash flow hedge is recognized in Other Comprehensive Income, andreclassified into earnings in the same period or periods during which thehedged transaction affects earnings.  Theineffective portion of a derivative instrument’s change in fair value isrecognized in current earnings.

 

***Commodity Cash FlowHedges******—***NSP-Minnesota enters into derivativeinstruments to manage variability of future cash flows from changes incommodity prices.  These derivativeinstruments are designated as cash flow hedges for accounting purposes.  At Dec. 31, 2004, NSP-Minnesota had variouscommodity-related contracts classified as cash flow hedges extending through2005.  Amounts deferred from currentearnings are recorded in earnings as the hedged purchase or sales transactionis settled.  This could include thepurchase or sale of energy and energy-related products, the use of natural gasto generate electric energy or natural gas purchased for resale.

 

As of Dec. 31, 2004, NSP-Minnesota had no amounts accumulated in OtherComprehensive Income that are expected to be recognized in earnings during thenext 12 months as the hedged transactions settle.

 

NSP-Minnesota had no ineffectiveness related to commodity cash flowhedges during the years ended Dec. 31, 2004 and 2003, respectively.

 

48

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***Financial Impacts of QualifyingCash Flow Hedges*** — The impact of qualifying cashflow hedges on NSP-Minnesota’s Other Comprehensive Income, included in theConsolidated Statements of Stockholder’s Equity, are detailed in the followingtable:

 
| **(Millions of Dollars)**                                                            | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------|------------|------------|------------|
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2001           |       | $          | 0.1        |   |
| After-tax net unrealized gains related to  derivatives accounted for as hedges       |       | —     |       |
| After-tax net realized gains on derivative  transactions reclassified into earnings  |       | (0.1       | )          |
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2002           |       | $          | —     |   |
|                                                                                 |       |       |       |
| After-tax net unrealized losses related to  derivative accounted for as hedges       |       | (0.2       | )          |
| After-tax net realized losses on derivative  transactions reclassified into earnings |       | 0.2        |       |
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2003           |       | $          | —     |   |
|                                                                                 |       |       |       |
| After-tax net unrealized losses related to  derivatives accounted for as hedges      |       | (0.7       | )          |
| After-tax net realized losses on derivative  transactions reclassified into earnings |       | 0.7        |       |
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2004           |       | $          | —     |   |

 

**Fair ValueHedges**

 

The effective portion ofthe change in the fair value of a derivative instrument qualifying as a fairvalue hedge is offset against the change in the fair value of the underlyingasset, liability or firm commitment being hedged.  That is, fair value hedge accounting allowsthe gains or losses of the derivative instrument to offset, in the same period,the gains and losses of the hedged item. The ineffective portion of a derivative instrument's change in fairvalue is recognized in current earnings.

 

At Dec. 31, 2004,NSP-Minnesota had no fair value hedges.

 

**NormalPurchases or Normal Sales Contracts**

 

NSP-Minnesota enters intocontracts for the purchase and sale of various commodities for use in itsbusiness operations.  SFAS No. 133requires a company to evaluate these contracts to determine whether thecontracts are derivatives.  Certaincontracts that literally meet the definition of a derivative may be exemptedfrom SFAS No. 133, as amended, as normal purchases or normal sales.  Normal purchases and normal sales arecontracts that provide for the purchase or sale of something other than afinancial instrument or derivative instrument that will be delivered inquantities expected to be used or sold over a reasonable period in the normalcourse of business.  In addition, normalpurchases and normal sales contracts must have a price based on an underlyingthat is clearly and closely related to the asset being purchased or sold.  An underlying is a specified interest rate,security price, commodity price, foreign exchange rate, index of prices orrates, or other variable, including the occurrence or nonoccurrence of a specifiedevent, such as a scheduled payment under a contract.

 

Contracts that meet therequirements of normal are documented and exempted from the accounting andreporting requirements of SFAS No. 133. In June 2003, C20 clarified the terms clearly and closely related tonormal purchases and sales contracts, as included in SFAS No. 133, asamended.  NSP-Minnesota’s implementationof C20 in 2003 had no impact on earnings. However, certain contracts did require a one-time fair value adjustmentas of Oct. 1, 2003.  The result of thisadjustment was the creation of a derivative liability with an offsettingregulatory asset to reflect expected recovery of the amounts fromcustomers.  The derivative liability andrelated regulatory asset will be amortized over the respective lives of thecontracts.  See Note 13 to theConsolidated Financial Statements.

 

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

 

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

 

The fair value ofqualifying hedges is presented as a component of Other Comprehensive Income inthe Consolidated Statements of Stockholder’s Equity.  At Dec. 31, 2004 and 2003, the fair value ofthese contracts was $(7.2) million and $(0.7) million, respectively.

 

The fair value of thetrading contracts as of Dec. 31, 2004 and 2003 was $0.9 million and $3.5million, respectively.

 

49

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

 

**10.Financial Instruments**

 

The estimated Dec. 31 fairvalues of NSP-Minnesota’s financial instruments are as follows:

 

| ** **                                | ** ** | **2004**             | ** ** | **2003**       | ** ** |
|-------------------------------------------|------------|----------------------|------------|----------------|------------|
| **(Thousands of  dollars)**               | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** |
| Long-term investments                     |       | $                    | 922,571    |           | $          | 922,571 |   | $ | 781,951 |   | $ | 781,952 |   |
| Long-term debt, including current portion |       | 1,941,922            |       | 2,193,546      |       | 1,945,460 |   | 2,191,052 |   |
|                                           |            |                      |            |                |            |  |  |  |  |  |  |  |  |

 

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

 

The fair value estimatespresented are based on information available to management as of Dec. 31, 2004and 2003. These fair value estimates have not been comprehensively revalued forpurposes of these Consolidated Financial Statements since that date, andcurrent estimates of fair values may differ significantly.

 

NSP-Minnesota providesguarantees that guarantee payment or performance under specified agreements ortransactions.  As a result, NSP-Minnesota’sexposure under the guarantees is based upon the net liability under thespecified agreements or transactions. The guarantees issued by NSP-Minnesota limit the exposure ofNSP-Minnesota to a maximum amount stated in the guarantees.  The guarantees require no liability to berecorded and contain no recourse provisions. On Dec. 31, 2004, NSP-Minnesota had the following guarantees andexposures related to those guarantees:

 
| **(Millions of dollars)  Nature of Guarantee**                                                                                                                                                                                                                                                                                                                                                                                                                                         | ** ** | **Guarantor** | ** ** | **Guarantee  Amount** | ** ** | **Current  Exposure** | ** ** | **Term or Expiration Date** | ** ** | **Triggering  Event  Requiring****Performance** | ** ** | **Assets Held as  Collateral** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------|------------|-----------------------|------------|-----------------------|------------|-----------------------------|------------|-------------------------------------------------|------------|--------------------------------|------------|
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |       |          |       |                  |       |                  |       |                        |       |                                            |       |                           |       |
| NSP-Minnesota sold a portion of its  receivables (consisting of customer loans to local and state government  entities for energy efficiency improvements) to a third party. Under the loan  agreements, NSP-Minnesota is required to guarantee repayment to the third  party of the remaining loan balances. Based on prior collection experience of  these loans, losses under the loan guarantees, if any, are not expected to  have a material impact on the results of operations |       | NSP-Minnesota |       | $                     | 0.4        |                  | $          | 0.4                         |       | Latest  expiration in 2007                      |       |                           | (a)        |   | (b) |
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |            |               |            |                       |            |                       |            |                             |            |                                                 |            |                                |            |  |  |

 

----

(a)  Nonpayment by the government entity on theunderlying debt

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

 

 

50

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# ** **

# **Lettersof Credit**

 

NSP-Minnesota uses lettersof credit, generally with terms of one year, to provide financial guaranteesfor certain operating obligations.  AtDec. 31, 2004, there was $39.4 million of letters of credit outstanding.  The contract amounts of these letters ofcredit approximate their fair value and are subject to fees determined in themarketplace.

 

**11.Commitments and Contingent Liabilities**

 

***Legislative Resource Commitments —***In 1994 and 2003, NSP-Minnesota receivedMinnesota legislative approval for additional on-site temporary spent-fuelstorage facilities at its Prairie Island nuclear power plant, providedNSP-Minnesota satisfies certain requirements. Commitments related to the 17 dry cask storage containers approved in1994 have been fulfilled.  The use of 29dry cask storage containers has been approved. As of Dec. 31, 2004,NSP-Minnesota had loaded 17 of the containers.

 

On May 29, 2003, theMinnesota Legislature enacted legislation that will enable NSP-Minnesota tostore at least 12 more casks of spent-fuel outside the Prairie Island nuclear generatingplant, in addition to those approved in 1994. This will allow NSP-Minnesota tocontinue to operate the plant and store spent-fuel in the facility until itslicenses with the Nuclear Regulatory Commission (NRC) expire in 2013 and 2014.The legislation transfers the primary authority concerning future spent-fuelstorage issues from the state Legislature to the MPUC.  It also allows for additional storage withoutthe requirement of an affirmative vote from the state Legislature, if the NRCextends the licenses of the Prairie Island and Monticello plants and the MPUCgrants a certificate of need for such additional storage. The legislationrequires NSP-Minnesota to add at least 300 megawatts of additional wind powerby 2010 with an option to own 100 megawatts of this power.

 

The legislation alsorequires payments during the remaining operating life of the Prairie Islandplant. These payments include: $2.25 million per year to the Prairie IslandTribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservationprogram expenditures (estimated at $2 million per year) to the University ofMinnesota for renewable energy research; and an increase in funding commitmentsto the previously established Renewable Energy Development Fund from $8.5 millionin 2002 to $16 million per year beginning in 2003. The legislation alsodesignated $10 million in one-time grants to the University of Minnesota foradditional renewable energy research, which is to be funded from commitmentsalready made to the Renewable Energy Development Fund. All of the costincreases to NSP-Minnesota from these required payments and funding commitmentsare expected to be recoverable in Minnesota retail customer rates, mainlythrough existing cost recovery mechanisms. Funding commitments to the RenewableEnergy Development Fund would terminate after the Prairie Island plantdiscontinues operation unless the MPUC determines that NSP-Minnesota failed tomake a good faith effort to store or dispose of the spent fuel out of state, inwhich case NSP-Minnesota would have to make payments in the amount of $7.5million per year.

 

***Capital Commitments*****—NSP-Minnesota expects to incur approximately $43 million in capitalexpenditures and $988 million for environmental improvements related to modificationsto reduce the emissions of NSP-Minnesota’s generating plants located in theMinneapolis-St. Paul metropolitan area pursuant to the metropolitan emissionsreduction project (MERP). The MERP project will begin major construction in2005 and finish in 2009. NSP-Minnesota expects cash recovery of the costs ofthe emission-reduction project through customer rates beginning in 2006.

 

***Leases*****—NSP-Minnesota leases a variety of equipment and facilities used in the normalcourse of business.  The leases areaccounted for as operating leases. Rental expense under operating lease obligations was approximately $27.3million, $27.1 million and $31.0 million for 2004, 2003 and 2002, respectively.

 

Expected operating leaseexpenses are:

 

| **2005**                  | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| **(Millions of dollars)** | ** ** |
| $                         | 27.7       |     | $          | 27.5     |       | $        | 27.5       |     | $          | 27.1 |   | $ | 26.7 |   |
|                           |            |          |            |          |            |          |            |          |            |  |  |  |  |  |

 

***Nuclear Insurance —***NSP-Minnesota’s public liability for claims resulting from any nuclearincident is limited to $10.8 billion under the 1988 Price-Anderson amendment tothe Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million ofcoverage for its public liability exposure with a pool of insurance companies.The remaining $10.5 billion of exposure is funded by the Secondary FinancialProtection Program, available from assessments by the federal government incase of a nuclear accident. NSP-Minnesota is subject to assessments of up to$100.6 million for each of its three licensed reactors, to be applied forpublic liability arising from a nuclear incident at any licensed nuclearfacility in the United States. The maximum funding requirement is $10 millionper reactor during any one year.

 

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NSP-Minnesota purchasesinsurance for property damage and site decontamination cleanup costs fromNuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billionfor each of NSP-Minnesota’s two nuclear plant sites. NEIL also providesbusiness interruption insurance coverage, including the cost of replacementpower obtained during certain prolonged accidental outages of nucleargenerating units. Premiums are expensed over the policy term. All companiesinsured with NEIL are subject to retroactive premium adjustments if lossesexceed accumulated reserve funds. Capital has been accumulated in the reservefunds of NEIL to the extent that NSP-Minnesota would have no exposure forretroactive premium assessments in case of a single incident under the businessinterruption and the property damage insurance coverage. However, in each calendaryear, NSP-Minnesota could be subject to maximum assessments of approximately$6.9 million for business interruption insurance and $26.1 million for propertydamage insurance if losses exceed accumulated reserve funds.

 

***Fuel Contracts*****—NSP-Minnesota has contracts providing for the purchase and delivery of asignificant portion of its current coal, nuclear fuel and natural gasrequirements. These contracts expire in various years between 2005 and 2017. Inaddition, NSP-Minnesota is required to pay additional amounts depending onactual quantities shipped under these agreements. The potential risk of loss inthe form of increased costs, from market price changes in fuel is mitigatedthrough the cost-of-energy adjustment provision of the ratemaking process,which provides for recovery of most fuel costs.

 

The estimated minimumpurchase for NSP-Minnesota under these contracts as of Dec. 31, 2004, is asfollows:

 
| **Coal**                  | ** ** | **Nuclear Fuel** | ** ** | **Natural Gas  Supply** | ** ** | **Gas Storage &  Transportation** | ** ** |
|---------------------------|------------|------------------|------------|-------------------------|------------|---------------------------------------|------------|
| **(Millions of dollars)** | ** ** |
| ** **                | ** ** | ** **       | ** ** | ** **              | ** ** | ** **                            | ** ** |
| $                         | 258        |             | $          | 133                     |       | $                                     | 673        |   | $ | 417 |   |
|                           |            |                  |            |                         |            |                                       |            |  |  |  |  |

 

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

 

At Dec. 31, 2004, theestimated future payments for capacity that NSP-Minnesota is obligated topurchase, subject to availability, is as follows (Thousands of dollars):

 
| 2005                 |   | $         | 106,648   |   |
|----------------------|--------|-----------|-----------|--------|
| 2006                 |   | 148,574   |      |
| 2007                 |   | 154,289   |      |
| 2008                 |   | 157,098   |      |
| 2009                 |   | 160,396   |      |
| 2010 and  thereafter |   | 1,826,820 |      |
| Total                |   | $         | 2,553,825 |   |
|                      |        |           |           |        |  |

 

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

 

**EnvironmentalContingencies**

 

NSP-Minnesota is subject toregulations covering air and water quality, the storage of natural gas and thestorage and disposal of hazardous or toxic wastes. We continuously assess ourcompliance. Regulations, interpretations and enforcement policies can change,which may impact the cost of building and operating our facilities.

 

***Site Remediation****—*NSP-Minnesotamust pay all or a portion of the cost to remediate sites where past activitiesof NSP-Minnesota and some other parties have caused environmentalcontamination. At Dec. 31, 2004 there were three categories of sites:

 

•        thesite of a former federal uranium enrichment facility,

 

•        thesite of former a manufactured gas plant (MGP) operated by NSP-Minnesota’ssubsidiaries or predecessors and

 

•                       third party sites, such aslandfills, to which we are alleged to be a potentially responsible party (PRP)that sent hazardous materials and wastes.

 

NSP-Minnesota records aliability when enough information is available to develop an estimate of thecost of remediating a site and

 

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revise the estimate asinformation is received. The estimated remediation cost may vary materially.

 

To estimate the cost toremediate these sites, assumptions are made where facts are not fully known.For instance, assumptions may be made about the nature and extent of sitecontamination, the extent of required cleanup efforts, costs of alternativecleanup methods and pollution control technologies, the period over whichremediation will be performed and paid for, changes in environmental remediationand pollution control requirements, the potential effect of technologicalimprovements, the number and financial strength of other PRPs and theidentification of new environmental cleanup sites.

 

Estimates are revised asfacts become known, but at Dec. 31, 2004, NSP-Minnesota estimated its liabilityfor the cost of remediating sites was $16.2 million, of which $7.5 million wasconsidered to be a current liability.

 

Some of the cost ofremediation may be recovered from:

 

•        insurancecoverage;

 

•        otherparties that have contributed to the contamination; and

 

•        customers.

 

Neither the totalremediation cost nor the final method of cost allocation among all PRPs of theunremediated sites has been determined. NSP-Minnesota has recorded estimates of its future costs for thesesites.

 

***Federal Uranium Enrichment Facility***

 

Approximately $4.6 millionof the long-term liability and $4.6 million of the current liability forNSP-Minnesota relates to a DOE assessment for decommissioning a federal uraniumenrichment facility. This environmental liability does not include accrualsrecorded and collected from customers in rates for future nuclear fuel disposalcosts or decommissioning costs related to NSP-Minnesota’s nuclear generatingplants. See Note 12 to Consolidated Financial Statements for further discussionof nuclear obligations.

 

###### ***Manufactured Gas Plant Site***

###### *** ***

***Levee StationManufactured Gas Plant Site****—* A portion ofNSP-Minnesota’s High Bridge plant coal yard is located on the site of theformer Levee Station MGP site. The Levee Station was a coke-oven gaspurification, storage and distribution facility.  The Levee Station supplied manufactured gasto the city of St. Paul from 1918 to the early 1950s.  In the 1950s, the facility was demolished,and the High Bridge coal yard was extended onto the property.  In the 1990s, the site was investigated andpartially remediated at a cost of approximately $2.9 million.  In 2006, NSP-Minnesota plans to commenceconstruction of the High Bridge Combined Cycle Generating Plant, as part ofMERP, on the site of the Levee Station. The construction of the new plant willrequire the removal of buried structures and soil and groundwater remediation.Remediation activities will begin in 2005. The cost of the additionalremediation is estimated to be $5.8 million, which will be accounted for as acapital expenditure of the MERP project.

 

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

 

***Asbestos Removal****—*Someof our facilities contain asbestos. Most asbestos will remain undisturbed untilthe facilities that contain it are demolished or renovated. Since we intend tooperate most of these facilities indefinitely, we cannot estimate the amount ortiming of payments for its final removal. It may be necessary to remove someasbestos to perform maintenance or make improvements to other equipment. Thecost of removing asbestos as part of other work is immaterial and is recordedas incurred as operating expenses for maintenance projects, capitalexpenditures for construction projects or removal costs for demolitionprojects.

 

***Federal Clean Water Act****—* The federalClean Water Act addresses the environmental impacts of cooling water intakes.In July 2004, the EPA published phase II of the rule that applies to existingcooling water intakes at steam-electric power plants. The rule will requireNSP-Minnesota to perform additional environmental studies at 7 power plants inMinnesota to determine the impact the facilities may be having on aquaticorganisms vulnerable to injury.  If thestudies determine the plants are not meeting the new performance standardsestablished by the phase II rule, physical and/or operational changes may berequired at these plants.  It is notpossible to provide an accurate estimate of the overall cost of this rulemakingat this time due to the many uncertainties involved. Preliminary cost estimatesrange from less than $1 million at some plants to more than $10 million atothers depending on site-specific circumstances. Based on the limitedinformation available, total capital costs to NSP-Minnesota are estimated atapproximately $55 million. Actual costs may be significantly higher or lowerdepending on issues such as the resolution of outstanding third-party legalchallenges to the rule.

 

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***New Source Review (NSR) Information Request*****— On Nov. 3, 1999, the U. S. Department ofJustice filed suit, related to alleged modifications of electric generatingplants located in the South and Midwest, against a number of electric utilitiesfor alleged violations of the Clean Air Act’s NSR requirements. Subsequently,the EPA also issued requests for information pursuant to the Clean Air Act tonumerous other electric utilities, including NSP-Minnesota, seeking todetermine whether these utilities engaged in activities that may have been inviolation of the NSR requirements. In 2001, NSP-Minnesota responded to the EPA’sinitial information requests.  On May 22,2002, the EPA issued a follow-up information request to NSP-Minnesota seeking additionalinformation regarding NSR compliance at its plants in Minnesota.  NSP-Minnesota completed its response to thefollow-up information request during the fall of 2002.

 

**LegalContingencies**

 

In the normal course ofbusiness, NSP-Minnesota is party to routine claims and litigation arising fromprior and current operations. NSP-Minnesota is actively defending these mattersand has recorded an estimate of the probable cost of settlement or otherdisposition.

 

***SchlumbergerSema,Inc. vs. Xcel Energy Inc.****—*Under a 1996data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meterreading, distribution automation and other data services to NSP-Minnesota.  In September 2002, NSP-Minnesota issuedwritten notice that SLB committed events of default under the agreement,including SLB’s nonpayment of approximately $7.4 million for distributionautomation assets.  In November 2002, SLBdemanded arbitration and asserted various claims against NSP-Minnesota totalingapproximately $24 million for alleged breach of an expansion contract and ameter-purchasing contract. In the arbitration, NSP-Minnesota assertedcounterclaims against SLB, including those related to SLB’s failure to meetperformance criteria, improper billing, failure to pay for use of NSP-Minnesotaowned property and failure to pay $7.4 million for NSP-Minnesota distributionautomation assets, for total claims of approximately $41 million. NSP-Minnesotaalso sought a declaratory judgment from the arbitrators that would terminateSLB’s rights under the data services agreement. In August 2004, the U.S. Bankruptcy Court for the District of Delawareruled that claims related to use of certain equipment are barred unlessNSP-Minnesota can establish a basis for the claims in SLB’s conduct subsequentto the time of the assumption of this contract by SLB.  If NSP-Minnesota cannot establish that basis,the decision would reduce NSP-Minnesota’s damage claim by approximately $5.5million.

 

***Metropolitan Airports Commission vs. Northern States Power Company****—* On Dec. 30, 2004, the Metropolitan AirportsCommission (MAC) filed a complaint in Minnesota state district court assertingthat NSP-Minnesota is required to relocate facilities on MAC property at theexpense of NSP-Minnesota.  MAC claimsthat approximately $7.1 million that NSP-Minnesota has charged over the pastfive years for relocation costs should be repaid.  The case is in early stages, there has beenno discovery and NSP-Minnesota intends to vigorously defend against theseclaims.

 

***Carbon Dioxide Emissions Lawsuit****—*On July 21,2004, the attorneys general of eight states and New York City, as well asseveral environmental groups, filed lawsuits in U.S. District Court for theSouthern District of New York against five utilities, including Xcel Energy, toforce reductions in carbon dioxide (CO2) emissions.  Although NSP-Minnesota is not named as aparty to this litigation, the requested relief that Xcel Energy cap and reduceits CO2 emissions could have a material adverse effect on NSP-Minnesota.  The other utilities include American ElectricPower Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2is emitted whenever fossil fuel is combusted, such as in automobiles,industrial operations and coal- or gas-fired power plants.  The lawsuits allege that CO2emitted by each company is a public nuisance as defined under state and federalcommon law because it has contributed to global warming.  The lawsuits do not demand monetarydamages.  Instead, the lawsuits ask thecourt to order each utility to cap and reduce its CO2emissions.  In October 2004, Xcel Energyand four other utility companies filed a motion to dismiss the lawsuitcontending, among other reasons, that the lawsuit should be dismissed becauseit is an attempt to usurp the policy-setting role of the U.S Congress and thepresident. The ultimate financial impact of these lawsuits, if any, is notdeterminable at this time.

 

The issue of global climate change is receiving increasedattention.  Debate continues in thescientific community concerning the extent to which the earth’s climate iswarming, the causes of climate variations that have been observed, and theultimate impacts that might result from a changing climate.  There also is considerable debate regardingpublic policy for the approach that the United States should follow to addressthe issue.  The United Nations-sponsoredKyoto Protocol, which establishes greenhouse gas reduction targets fordeveloped nations, entered into force on Feb. 16, 2005.  President Bush has declared that the UnitedStates will not ratify the protocol and is opposed to legislative mandates,preferring a program based on voluntary efforts and research on newtechnologies.  NSP-Minnesota is closelymonitoring the issue from both scientific and policy perspectives.  While it is not possible to know the eventualoutcome, NSP-Minnesota believes the issue merits close attention and is takingactions it believes are prudent to be best positioned for a variety of possiblefuture outcomes.  Xcel Energy, includingNSP-Minnesota, is participating in a voluntary carbon

 

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management program and has established goals to reduce its volume ofcarbon dioxide emissions by 12 million tons by 2009 and to reduce carbonintensity by 7 percent by 2012. NSP-Minnesota’s evaluation process for future generating resourcesincorporates the risk of future carbon limits through the use of externalitycosts.  NSP-Minnesota also is involved inother projects to improve available methods for managing carbon.

 

**12. Nuclearand Other Asset Retirement Obligations**

 

NSP-Minnesota records futureplant decommissioning obligations as a liability at fair value with acorresponding increase to the carrying values of the related long-lived assets.This liability will be increased over time by applying the interest method ofaccretion to the liability, and the capitalized costs will be depreciated overthe useful life of the related long-lived assets.  The recording of the obligation has no incomestatement impact due to the deferral of adjustments through the establishmentof a regulatory asset pursuant to SFAS No. 71.

 

Asset retirement obligationshave been recorded for the decommissioning of two NSP-Minnesota nucleargenerating plants, the Monticello plant and the Prairie Island plant. Aliability also has been recorded for decommissioning of an NSP-Minnesota steamproduction plant, the Pathfinder plant. Monticello began operation in 1971 and is licensed to operate until2010. Prairie Island units 1 and 2 began operation in 1973 and 1974,respectively, and are licensed to operate until 2013 and 2014, respectively.Pathfinder operated as a steam production peaking facility from 1969 until itsretirement.

 

A reconciliation of thebeginning and ending aggregate carrying amount of NSP-Minnesota’s assetretirement obligations are shown in the table below for the 12 months endedDec. 31, 2004:

 

| **(Thousands of dollars)**    | ** ** | **Beginning  Balance  Jan. 1, 2004** | ** ** | **Liabilities  Incurred** | ** ** | **Liabilities  Settled** | ** ** | **Accretion** | ** ** | **Revisions  To Prior  Estimates** | ** ** | **Ending  Balance  Dec. 31, 2004** | ** ** |
|-------------------------------|------------|--------------------------------------|------------|---------------------------|------------|--------------------------|------------|---------------|------------|------------------------------------|------------|------------------------------------|------------|
| ** **                    | ** ** | ** **                           | ** ** | ** **                | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                         | ** ** | ** **                         | ** ** |
| Steam plant retirement        |       | $                                    | 2,860      |                      | $          | —                   |       | $             | —     |                               | $          | 142                                |       | $ | — |   | $ | 3,002 |   |
| Nuclear plant decommissioning |       | 1,021,669                            |       | —                    |       | —                   |       | 66,418        |       | —                             |       | 1,088,087                          |       |
| Total liability               |       | $                                    | 1,024,529  |                      | $          | —                   |       | $             | —     |                               | $          | 66,560                             |       | $ | — |   | $ | 1,091,089 |   |
|                               |            |                                      |            |                           |            |                          |            |               |            |                                    |            |                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

The fair value ofNSP-Minnesota assets legally restricted for purposes of settling the nuclearasset retirement obligations is $986 million as of Dec. 31, 2004, includingexternal nuclear decommissioning investment funds and internally fundedamounts.

 

***Removal Costs*****—NSP-Minnesota also accrues an obligationfor plant removal costs for other generation, transmission and distributionfacilities.  Generally, the accrual offuture non-legal removal obligations is not required.  However, long-standing ratemaking practicesapproved by applicable state and federal regulatory commissions have allowedprovisions for such costs in historical depreciation rates. These removal costshave accumulated over a number of years based on varying rates as authorized bythe appropriate regulatory entities. Given the long periods over which theamounts were accrued and the changing of rates through time, the NSP-Minnesotahas estimated the amount of removal costs accumulated through historicdepreciation expense based on current factors used in the existing depreciationrates.  Accordingly, the recorded amountsof estimated future removal costs are considered Regulatory Liabilities under SFASNo. 71. Removal costs as of Dec. 31, 2004 and 2003 are $323 million and $324million, respectively.

 

***Fuel Disposal*****—NSP-Minnesota is responsible for temporarily storing used or spent-nuclear fuelfrom its nuclear plants. The DOE is responsible for permanently storingspent-fuel from NSP-Minnesota’s nuclear plants as well as from other U.S.nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanentdisposal program since 1981. The fuel disposal fees are based on a charge of0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuelexpense includes DOE fuel disposal assessments of approximately $13 million in2004, $13 million in 2003 and $13 million in 2002. In total, NSP-Minnesota hadpaid approximately $335 million to the DOE through Dec. 31, 2004. However, itis not determinable whether the amount and method of the DOE’s assessments toall utilities will be sufficient to fully fund the DOE’s permanent storage ordisposal facility.

 

The Nuclear Waste PolicyAct required the DOE to begin accepting spent-nuclear fuel no later than Jan.31, 1998. In 1996, the DOE notified commercial spent-fuel owners of ananticipated delay in accepting spent-nuclear fuel by the required date andconceded that a permanent storage or disposal facility will not be availableuntil at least 2010. NSP-Minnesota and other utilities have commenced lawsuitsagainst the DOE to recover damages caused by the DOE’s failure to meet itsstatutory and contractual obligations.

 

NSP-Minnesota has its owntemporary, on-site storage facilities for spent-fuel at its Monticello andPrairie Island nuclear plants, which consists of storage pools and a dry caskfacility. With the dry cask storage facility licensed by the NRC approved in1994 and again in 2003, management believes it has adequate storage capacity tocontinue operation of its Prairie Island nuclear plant until at

 

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least the end of its licenseterms in 2013 and 2014. The Monticello nuclear plant has storage capacity inthe pool to continue operations until 2010. Storage availability to permitoperation beyond these dates is not known at this time. All of the alternativesfor spent-fuel storage are being investigated until a DOE facility isavailable, including pursuing the establishment of a private facility forinterim storage of spent-nuclear fuel as part of a consortium of electricutilities.

 

Nuclear fuel expenseincludes payments to the DOE for the decommissioning and decontamination of theDOE’s uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’sinitial assessment of $46 million, which is payable in annual installments from1993 to 2008. NSP-Minnesota is amortizing each installment to expense on amonthly basis. The most recent installment paid in 2004 was $4.6 million;future installments are subject to inflation adjustments under DOE rules.NSP-Minnesota is obtaining rate recovery of these DOE assessments through thecost-of-energy adjustment clause as the assessments are amortized. Accordingly,the unamortized assessment of $12.6 million at Dec. 31, 2004, is deferred as aregulatory asset.

 

***Regulatory Plant Decommissioning Recovery*****— Decommissioning of NSP-Minnesota’s nuclearfacilities, as last approved by the MPUC, is planned for the years 2010 through2048, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the costs for decommissioning over theMPUC approved cost-recovery period and including the accruals in AccumulatedDepreciation.  Upon implementation ofSFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoingrecoveries are reclassified to a regulatory liability account. The totaldecommissioning cost obligation is recorded as an asset retirement obligationin accordance with SFAS No. 143.

 

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

 

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

 

The MPUC last approvedNSP-Minnesota’s nuclear decommissioning study request in December 2003, using2002 cost data. An original filing was submitted to the MPUC in October 2002and updated in August 2003; final approval was received in December 2003. Themost recent cost estimate represents an annual increase in external fundaccruals, along with the extension of Prairie Island cost recovery to the endof license life in 2014. The MPUC also approved the Department of Commercerecommendation to accelerate the internal fund transfer to the external fundseffective July 1, 2003, ending on Dec. 31, 2005. This approval increased thefund cash contribution by approximately $29 million in 2003.  Consistent with previous treatment, thetransfers from the internal fund are effectively moving previously collectedfunds to the external fund, thereby reducing the external fund bookexpense.  Based on the last MPUC approvalrequiring the acceleration of the internal fund transfer, there is a stepchange in the level of the overall decommissioning expense at the expiration ofthe transfer beginning Jan. 1, 2006. Expecting to operate Prairie Island throughthe end of each unit’s licensed life, the approved capital recovery will allowfor the plant to be fully depreciated, including the accrual and recovery ofdecommissioning costs, in 2014. NSP-Minnesota believes future decommissioning cost accruals willcontinue to be recovered in customer rates.

 

The total obligation fordecommissioning currently is expected to be funded 100 percent by externalfunds, as approved by the MPUC. Contributions to the external fund started in1990 and are expected to continue until plant decommissioning begins. Theassets held in trusts as of Dec. 31, 2004, primarily consisted of investmentsin fixed income securities, such as tax-exempt municipal bonds and U.S.government securities that mature in one to 20 years, and common stock ofpublic companies. NSP-Minnesota plans to reinvest matured securities untildecommissioning begins.

 

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At Dec. 31, 2004,NSP-Minnesota had recorded and recovered in rates cumulative decommissioningaccruals of $768 million. The following table summarizes the funded status ofNSP-Minnesota’s decommissioning obligation based on approved regulatoryrecovery parameters.  These amounts arenot those recorded in the financial statements for the asset retirementobligation in accordance with SFAS No. 143:

 
| ** **                                                                                  | ** ** | **2004**                    | ** ** |
|---------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                  | ** ** | **(Thousands  of dollars)** | ** ** |
| Estimated decommissioning cost obligation  from most recently approved study (2002 dollars) |       | $                           | 1,716,618  |   |
| Effect of escalating costs to 2004 dollars  (at 4.19 percent per year)                      |       | 146,866                     |       |
| Estimated decommissioning cost obligation  in current dollars                               |       | 1,863,484                   |       |
| Effect of escalating costs to payment date  (at 4.19 percent per year)                      |       | 1,929,881                   |       |
| Estimated future decommissioning costs  (undiscounted)                                      |       | 3,793,365                   |       |
| Effect of discounting obligation (using  risk-free interest rate)                           |       | (2,139,561                  | )          |
| Discounted decommissioning cost obligation                                                  |       | 1,653,804                   |       |
| Assets held in external decommissioning  trust                                              |       | 918,442                     |       |
| Discounted decommissioning obligation in  excess of assets currently held in external trust |       | $                           | 735,362    |   |

 

Decommissioning expensesrecognized include the following components:

 
| ** **                                                             | ** ** | **2004**                   | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------------------------------------|------------|----------------------------|------------|----------|------------|----------|------------|
| ** **                                                             | ** ** | **(Thousands of dollars)** | ** ** |
| Annual decommissioning cost accrual  reported as depreciation expense: |       |                       |       |     |       |     |       |
| Externally funded                                                      |       | $                          | 80,582     |     | $          | 80,582   |       | $ | 51,433 |   |
| Internally funded (including interest  costs)                          |       | (53,307                    | )          | (35,906  | )          | (18,797  | )          |
| Interest cost on externally funded  decommissioning obligation         |       | (19,026                    | )          | (14,952  | )          | (32      | )          |
| Earnings from external trust funds                                     |       | 19,026                     |       | 14,952   |       | 32       |       |
| Net decommissioning accruals recorded                                  |       | $                          | 27,275     |     | $          | 44,676   |       | $ | 32,636 |   |
|                                                                        |            |                            |            |          |            |          |            |  |  |  |  |  |  |

 

Decommissioning and interestaccruals are included with Regulatory Liabilities on the Consolidated BalanceSheet. Interest costs and trust earnings associated with externally fundedobligations are reported in Other Nonoperating Income on the ConsolidatedStatements of Income.

 

Negative accruals forinternally funded portions in 2002, 2003 and 2004 reflect the impacts of the1999 and 2002 decommissioning studies, which have approved an assumption of100-percent external funding of future costs. Previous studies assumed aportion was funded internally; beginning in 2000, accruals are reversing thepreviously accrued internal portion and increasing the external portionprospectively.

 

**13.Regulatory Assets and Liabilities**

 

NSP-Minnesota’s financialstatements are prepared in accordance with the provisions of SFAS No. 71, asdiscussed in Note 1 to the Consolidated Financial Statements. Under SFAS No.71, regulatory assets and liabilities can be created for amounts thatregulators may allow to be collected, or may require to be paid back tocustomers in future electric and natural gas rates. Any portion of the businessthat is not rate regulated cannot use SFAS No. 71 accounting. The components ofunamortized regulatory assets and liabilities on the balance sheets ofNSP-Minnesota are as follows:

 

| **(Thousands of dollars)**                         | ** ** | **See note** | ** ** | **Remaining amortization  period** | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|----------------------------------------------------|------------|--------------|------------|------------------------------------|------------|------------|------------|------------|------------|
| ** **                                         | ** ** | ** **   | ** ** | ** **                         | ** ** | ** ** | ** ** | ** ** | ** ** |
| Regulatory Assets:                                 |       |         |       |                               |       |       |       |       |       |
| Net nuclear asset retirement obligations           |       | 12           |       | End of  licensed life              |       | $          | 221,864    |       | $          | 186,989 |   |
| AFDC recorded in plant (a)                         |       |         |       | Plant lives                        |       | 92,080     |       | 85,552     |       |
| Purchase power contract valuation  adjustments (d) |       | 9            |       | Term of  contract                  |       | 17,700     |       | 78,446     |       |
| Losses on reacquired debt                          |       | 1            |       | Term of  related debt              |       | 32,844     |       | 36,623     |       |
| Renewable resource costs                           |       |         |       | To be  determined                  |       | 38,985     |       | 25,972     |       |
| Conservation programs (a)                          |       |         |       | Generally  one year                |       | 23,209     |       | 25,380     |       |
| Nuclear decommissioning costs (c)                  |       |         |       | Up to three  years                 |       | 12,610     |       | 16,750     |       |
| Unrecovered gas costs (b)                          |       | 1            |       | One to two  years                  |       | 14,553     |       | 16,008     |       |
| Other                                              |       |         |       | Various                            |       | 9,667      |       | 12,304     |       |
| Minnesota renewable cost recovery                  |       |         |       | Generally  one year                |       | 5,292      |       | —     |       |
| State commission accounting adjustments (a)        | %          |         |       | Plant lives                        |       | 4,476      |       | 4,604      |       |
| Environmental costs                                |       | 11,12        |       | Various                            |       | 3,205      |       | 3,863      |       |
| Total regulatory assets                            |       |         |       |                               |       | $          | 476,485    |       | $          | 492,491 |   |
|                                               |       |         |       |                               |       |       |       |       |       |
| Regulatory Liabilities:                            |       |         |       |                               |       |       |       |       |       |
| Pension costs-regulatory differences               |       | 7            |       |                               |       | 377,893    |       | 338,926    |       |
| Plant removal costs                                |       | 12           |       |                               |       | 323,440    |       | 324,637    |       |
| Unrealized gains on decommissioning  investments   |       | 12           |       |                               |       | 129,028    |       | 105,518    |       |
| Deferred income tax adjustments                    |       |         |       |                               |       | 60,521     |       | 65,749     |       |
| Investment tax credit deferrals                    |       |         |       |                               |       | 40,602     |       | 45,698     |       |
| Interest on income tax refunds                     |       |         |       |                               |       | 9,315      |       | 6,630      |       |
| Fuel costs, refunds and other                      |       |         |       |                               |       | 3,565      |       | 1,994      |       |
| Total regulatory liabilities                       |       |         |       |                               |       | $          | 944,364    |       | $          | 889,152 |   |
|                                                    |            |              |            |                                    |            |            |            |            |            |  |  |  |  |  |

 

57

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----

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

 

(b)      Excludes current portion expected to be returned to customers within 12months of $12.4 million for 2004, and expected to be recovered from customerswithin 12 months of $3.1 million for 2003

 

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

 

(d)      Regulatory assets created by the implementation of C20. See Note 9.

 

**14. Segmentand Related Information**

 

NSP-Minnesota has tworeportable segments, Regulated Electric Utility and Regulated Natural GasUtility.

 

•             NSP-Minnesota’s Regulated Electric Utilitygenerates, transmits and distributes electricity in Minnesota, North Dakota andSouth Dakota. In addition, this segment includes sales for resale and provideswholesale transmission service to various entities in the United States.Regulated Electric Utility also includes NSP-Minnesota’s commodity tradingoperations.

 

•             NSP-Minnesota’s Regulated Natural Gas Utilitytransports, stores and distributes natural gas in portions of Minnesota andNorth Dakota.

 

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

 

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

 

•              directlyassigned wherever applicable;

 

•              allocatedbased on cost causation allocators wherever applicable; or

 

•              allocated based on a generalallocator for all other costs not assigned by the above two methods.

 

The accounting policies ofthe segments are the same as those described in Note 1 to the ConsolidatedFinancial Statements.

 

58

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| ** **                                 | ** ** | **Regulated  Electric  Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|--------------------------------------------|------------|----------------------------------|------------|-------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| ** **                                 | ** ** | **(Thousands of dollars)**       | ** ** |
| **2004**                                   |       |                             |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                                | 2,585,356  |                                | $          | 715,071        |       | $                             | 19,135     |                    | $          | — |   | $ | 3,319,562 |   |
| Intersegment revenues                      |       | 821                              |       | 4,658                               |       |           |       | (5,479                        | )          |                    |       |
| Total revenues                             |       | 2,586,177                        |       | 719,729                             |       | 19,135         |       | (5,479                        | )          | 3,319,562               |       |
| Depreciation and amortization              |       | 307,048                          |       | 28,787                              |       | 909            |       | —                        |       | 336,744                 |       |
| Financing costs, mainly interest expense   |       | 113,405                          |       | 14,349                              |       | 875            |       | (47                           | )          | 128,582                 |       |
| Income tax expense (benefit)               |       | 90,428                           |       | 7,332                               |       | (3,147         | )          | —                        |       | 94,613                  |       |
| Segment net income                         |       | $                                | 206,726    |                                | $          | 23,131         |       | $                             | 417        |                    | $          | — |   | $ | 230,274 |   |
|                                       |       |                             |       |                                |       |           |       |                          |       |                    |       |
| **2003**                                   |       |                             |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                                | 2,485,742  |                                | $          | 674,530        |       | $                             | 17,180     |                    | $          | — |   | $ | 3,177,452 |   |
| Intersegment revenues                      |       | 720                              |       | 7,245                               |       | —         |       | (7,965                        | )          | —                  |       |
| Total revenues                             |       | 2,486,462                        |       | 681,775                             |       | 17,180         |       | (7,965                        | )          | 3,177,452               |       |
| Depreciation and amortization              |       | 318,801                          |       | 31,420                              |       | 3,120          |       | —                        |       | 353,341                 |       |
| Financing costs, mainly interest expense   |       | 117,332                          |       | 18,004                              |       | 10,180         |       | (9,876                        | )          | 135,640                 |       |
| Income tax expense                         |       | 67,104                           |       | 8,965                               |       | 455            |       | —                        |       | 76,524                  |       |
| Segment net income (loss)                  |       | $                                | 177,333    |                                | $          | 17,852         |       | $                             | (2,243     | )                       | $          | — |   | $ | 192,942 |   |
|                                       |       |                             |       |                                |       |           |       |                          |       |                    |       |
| **2002**                                   |       |                             |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                                | 2,362,672  |                                | $          | 489,572        |       | $                             | 30,875     |                    | $          | — |   | $ | 2,883,119 |   |
| Intersegment revenues                      |       | 602                              |       | 4,099                               |       | —         |       | (4,701                        | )          | —                  |       |
| Total revenues                             |       | 2,363,274                        |       | 493,671                             |       | 30,875         |       | (4,701                        | )          | 2,883,119               |       |
| Depreciation and amortization              |       | 325,738                          |       | 27,682                              |       | 737            |       | —                        |       | 354,157                 |       |
| Financing costs, mainly interest expense   |       | 101,336                          |       | 13,253                              |       | 16,909         |       | (16,808                       | )          | 114,690                 |       |
| Income tax expense                         |       | 99,873                           |       | 4,775                               |       | 3,493          |       | —                        |       | 108,141                 |       |
| Segment net income                         |       | $                                | 177,703    |                                | $          | 15,752         |       | $                             | 6,767      |                    | $          | — |   | $ | 200,222 |   |

 

**15. RelatedParty Transactions**

 

In 2003, Xcel Energyestablished a money pool arrangement with the utility subsidiaries, subject toreceipt of required state regulatory approvals. NSP-Minnesota received approval to participate in the money poolarrangement in 2004.  The money poolallows for short-term loans between the utility subsidiaries and from theholding company to the utility subsidiaries at market-based interest rates. Themoney pool arrangement does not allow loans from the utility subsidiaries tothe holding company. NSP-Minnesota has approval to borrow up to $250 millionunder the arrangement.  NSP-Minnesota hadno borrowings or loans outstanding under the arrangement at Dec. 31, 2004.

 

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

 

Viking Gas Transmission Co.(Viking), a subsidiary of Xcel Energy until it was sold on Jan. 17, 2003,transported gas purchased by NSP-Minnesota from various suppliers.  NSP-Minnesota paid Viking $4.6 million in2002 for gas transportation services.

 

NSP-Minnesota purchased gasfrom e prime, another subsidiary of Xcel Energy, paying $2.7 million in 2002.In addition NSP-Minnesota sold transportation services to e prime for $0.1million in 2002 for gas delivered into the Minnesota operating area.  e prime ceased conducting business in 2004.

 

Utility Engineering Corp.,an Xcel Energy subsidiary, provided construction services to NSP-Minnesota, forwhich it was paid $9.3 million in 2004, $5.3 million in 2003 and $5.1 millionin 2002.

 

NSP-Minnesota and four other utility companies formed the NMC, and eachof the five member companies retains a 20 percent ownership interest in theNMC.  The NMC is an operating companythat manages the operations, maintenance and physical security of eight nucleargenerating units on six sites, including three units/two sites owned byNSP-Minnesota.  NSP-Minnesota continuesto own the plants, controls all energy produced by the plants, and retainsresponsibility for nuclear property and liability insurance and decommissioningcosts.  In accordance with theNuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays itsproportionate share of the operating expenses and capital improvement costsincurred by NMC.  NSP-Minnesota paid NMC$314.7 million in 2004, $227.0 million in 2003 and $182.5 million in 2002.

 

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

 

The table below containssignificant affiliate transactions among the companies and related partiesincluding billings under the Interchange Agreement for the years ended Dec. 31:

 
| **(Thousands of dollars)**                                 | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Operating revenues:                                        |       |     |       |     |       |     |       |
| Electric utility                                           |       | $        | 220,165    |     | $          | 227,946  |       | $ | 220,674 |   |
| Natural gas utility                                        |       | 303      |       | 287      |       | 363      |       |
| Operating expenses:                                        |       |     |       |     |       |     |       |
| Purchased power                                            |       | 96,016   |       | 92,814   |       | 80,200   |       |
| Other operations – paid to Xcel Energy  Services Inc. |       | 274,074  |       | 266,560  |       | 272,825  |       |
|                                                            |            |          |            |          |            |          |            |  |  |  |

 

59

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Accounts receivable andpayable with affiliates at Dec. 31, was:

 
| ** **                             | ** ** | **2004**                 | ** ** | **2003**              | ** ** |
|----------------------------------------|------------|--------------------------|------------|-----------------------|------------|
| **(Thousands of dollars)**             | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** |
| ** **                             | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| NSP-Wisconsin                          |       | $                        | 2,826      |                  | $          | — |   | $ | — |   | $ | 329 |   |
| PSCo                                   |       | 72                       |       | 12,197                |       | 20 |   | 714 |   |
| SPS                                    |       | —                   |       | 1,576                 |       | — |   | 4,297 |   |
| Other subsidiaries of Xcel Energy Inc. |       | 5,452                    |       | 9,240                 |       | 48,796 |   | 27,544 |   |
|                                   |       | $                        | 8,350      |                  | $          | 23,013 |   | $ | 48,816 |   | $ | 32,884 |   |
|                                        |            |                          |            |                       |            |  |  |  |  |  |  |  |  |  |

 

NSP-Wisconsin obtainsshort-term borrowings from NSP-Minnesota at NSP-Minnesota’s average dailyinterest rate, including the cost of NSP-Minnesota’s compensating balancerequirements. As of Dec. 31, 2004, NSP-Minnesota had notes receivableoutstanding from NSP-Wisconsin in the amount of $31.5 million.  Interest income on NSP-Minnesota’s statementof income was $0.3 million, $0.1 million and $0.2 million for 2004, 2003 and2002.

 

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

 

| ** **       | ** ** | **Quarter Ended**          | ** ** |
|------------------|------------|----------------------------|------------|
| ** **       | ** ** | **March 31, 2004**         | ** ** | **June 30, 2004** | ** ** | **Sept. 30, 2004 (a)** | ** ** | **Dec. 31, 2004 (b)** | ** ** |
| ** **       | ** ** | **(Thousands of dollars)** | ** ** |
| ** **       | ** ** | ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenue          |       | $                          | 929,662    |   | $ | 696,941 |   | $ | 800,759 |   | $ | 892,200 |   |
| Operating income |       | 132,633                    |       | 77,703 |   | 127,182 |   | 94,115 |   |
| Net income       |       | 68,357                     |       | 34,263 |   | 68,435 |   | 59,219 |   |
|                  |            |                            |            |  |  |  |  |  |  |  |  |  |  |

 

| ** **       | ** ** | **Quarter Ended**          | ** ** |
|------------------|------------|----------------------------|------------|
| ** **       | ** ** | **March 31, 2003**         | ** ** | **June 30, 2003** | ** ** | **Sept. 30, 2003** | ** ** | **Dec. 31, 2003** | ** ** |
| ** **       | ** ** | **(Thousands of dollars)** | ** ** |
| ** **       | ** ** | ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenue          |       | $                          | 927,755    |   | $ | 667,261 |   | $ | 814,387 |   | $ | 768,049 |   |
| Operating income |       | 102,915                    |       | 45,469 |   | 155,225 |   | 91,623 |   |
| Net income       |       | 44,451                     |       | 19,641 |   | 80,410 |   | 48,440 |   |
|                  |            |                            |            |  |  |  |  |  |  |  |  |  |  |

----

(a)  Inthe third quarter of 2004, an adjustment of $9.8 million was recorded, whichlowered 2003 costs of NSP-Minnesota shared with NSP-Wisconsin, pursuant to theInterchange Agreement.  In addition, anadjustment, which reduced expenses charged to NSP-Wisconsin by NSP-Minnesota of$6.2 million was recorded for 2004 year-to-date billings. 

 

(b)  Fourthquarter 2004 results were increased by $10.5 million of income tax benefits,including $4.1 million related to the successful resolution of various IRSaudit issues and other adjustments to current and deferred taxes related toprior years, $5 million for the 2003 return- to- accrual true-up and $1.4million from revisions to benefits related to foreign power sales.

 

**Item 9****— Changes in and Disagreements With Accountants onAccounting and Financial Disclosure**

 

During 2003 and 2004, andthrough the date of this report, there were no disagreements with theindependent public accountants for NSP-Minnesota on accounting principles orpractices, financial disclosures or audit scope or procedures.

 

**Item 9A****— Controls and Procedures**

 

**DisclosureControls and Procedures**

 

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

 

**Internal Control Over Financial Reporting**

** **

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

 

**Item 9B******— **Other Information**

 

None

 

60

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**PART III**

 

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

 

**Item 10****— Directors and Executive Officers of the Registrant**

 

**Item 11****— Executive Compensation**

 

**Item 12****— Security Ownership of Certain Beneficial Owners andManagement**

 

**Item 13****— Certain Relationships and Related Transactions**

 

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

 

Information concerningfees paid to the principal accountant for each of the last two years iscontained in the Xcel Energy Proxy Statement for its 2005 Annual Meeting ofShareholders, which is incorporated by reference.

 

61

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**PART IV**

 

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

** **

1.               Consolidated Financial Statements:

Reports of Independent Registered Public Accounting Firm **—**For the years ended Dec. 31, 2004,2003 and 2002.

Consolidated Statements of Income **—**For the threeyears ended Dec. 31, 2004, 2003 and 2002.

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31, 2004, 2003 and2002.

Consolidated Balance Sheets **—**Asof Dec. 31, 2004 and 2003.

 

2.               Schedule II **—**Valuationand Qualifying Accounts and Reserves for the years ended Dec. 31, 2004, 2003and 2002.

 

3.               Exhibits

 

----

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans CoveringExecutive Officers and Directors

 
| 2.01* |   | Agreement and Plan of  Merger, dated as of March 24, 1999, by and between Northern States Power Co.  (a Minnesota corporation) and New Century Energies, Inc. (Exhibit 2.1 to New  Century Energies, Inc. Form  8-K (file no. 001-12907) dated March 24, 1999).                                                                                               |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.01* |   | Articles of Incorporation  and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a  Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file  no. 000-31709) dated Oct. 5, 2000).                                                                                                                                      |
| 3.02* |   | By-Laws of Northern States  Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 10-12G (file no.  000-31709) dated Oct. 5, 2000).                                                                                                                                                                                                                       |
| 4.01* |   | Trust Indenture, dated  Feb. 1, 1937, from Northern States Power Co. (a Minnesota corporation) to  Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to File No. 2-5290).                                                                                                                                                                               |
| 4.02* |   | 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 (file no. 001-03034) for the year 1988).  Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental  to Exhibit 4.02, dated as follows: |
| 4.03* |   | June 1, 1942 (Exhibit B-8  to File No. 2-97667).                                                                                                                                                                                                                                                                                                              |
| 4.04* |   | Feb. 1, 1944 (Exhibit B-9  to File No. 2-5290).                                                                                                                                                                                                                                                                                                               |
| 4.05* |   | Oct. 1, 1945 (Exhibit 7.09  to File No. 2-5924).                                                                                                                                                                                                                                                                                                              |
| 4.06* |   | July 1, 1948 (Exhibit 7.05  to File No. 2-7549).                                                                                                                                                                                                                                                                                                              |
| 4.07* |   | Aug. 1, 1949 (Exhibit 7.06  to File No. 2-8047).                                                                                                                                                                                                                                                                                                              |
| 4.08* |   | June 1, 1952 (Exhibit 4.08  to File No. 2-9631).                                                                                                                                                                                                                                                                                                              |
| 4.09* |   | Oct. 1, 1954 (Exhibit 4.10  to File No. 2-12216).                                                                                                                                                                                                                                                                                                             |
| 4.10* |   | Sept. 1, 1956 (Exhibit  2.09 to File No. 2-13463).                                                                                                                                                                                                                                                                                                            |
| 4.11* |   | Aug. 1, 1957 (Exhibit 2.10  to File No. 2-14156).                                                                                                                                                                                                                                                                                                             |
| 4.12* |   | July 1, 1958 (Exhibit 4.12  to File No. 2-15220).                                                                                                                                                                                                                                                                                                             |
| 4.13* |   | Dec. 1, 1960 (Exhibit 2.12  to File No. 2-18355).                                                                                                                                                                                                                                                                                                             |
| 4.14* |   | Aug. 1, 1961 (Exhibit 2.13  to File No. 2-20282).                                                                                                                                                                                                                                                                                                             |
| 4.15* |   | June 1, 1962 (Exhibit 2.14  to File No. 2-21601).                                                                                                                                                                                                                                                                                                             |
| 4.16* |   | Sept. 1, 1963 (Exhibit  4.16 to File No. 2-22476).                                                                                                                                                                                                                                                                                                            |
| 4.17* |   | Aug. 1, 1966 (Exhibit 2.16  to File No. 2-26338).                                                                                                                                                                                                                                                                                                             |
| 4.18* |   | June 1, 1967 (Exhibit 2.17  to File No. 2-27117).                                                                                                                                                                                                                                                                                                             |
| 4.19* |   | Oct. 1, 1967 (Exhibit  2.01R to File No. 2-28447).                                                                                                                                                                                                                                                                                                            |
| 4.20* |   | May 1, 1968 (Exhibit 2.01S  to File No. 2-34250).                                                                                                                                                                                                                                                                                                             |
| 4.21* |   | Oct. 1, 1969 (Exhibit  2.01T to File No. 2-36693).                                                                                                                                                                                                                                                                                                            |
| 4.22* |   | Feb. 1, 1971 (Exhibit  2.01U to File No. 2-39144).                                                                                                                                                                                                                                                                                                            |
| 4.23* |   | May 1, 1971 (Exhibit 2.01V  to File No. 2-39815).                                                                                                                                                                                                                                                                                                             |
| 4.24* |   | Feb. 1, 1972 (Exhibit  2.01W to File No. 2-42598).                                                                                                                                                                                                                                                                                                            |
| 4.25* |   | Jan. 1, 1973 (Exhibit  2.01X to File No. 2-46434).                                                                                                                                                                                                                                                                                                            |
| 4.26* |   | Jan. 1, 1974 (Exhibit  2.01Y to File No. 2-53235).                                                                                                                                                                                                                                                                                                            |
| 4.27* |   | Sept. 1, 1974 (Exhibit  2.01Z to File No. 2-53235).                                                                                                                                                                                                                                                                                                           |
| 4.28* |   | April 1, 1975 (Exhibit  4.01AA to File No. 2-71259).                                                                                                                                                                                                                                                                                                          |

 

62

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| 4.29*   |   | May 1, 1975 (Exhibit  4.01BB to File No. 2-71259).                                                                                                                                                                                                                                       |
|---------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.30*   |   | March 1, 1976 (Exhibit  4.01CC to File No. 2-71259).                                                                                                                                                                                                                                     |
| 4.31*   |   | June 1, 1981 (Exhibit  4.01DD to File No. 2-71259).                                                                                                                                                                                                                                      |
| 4.32*   |   | Dec. 1, 1981 (Exhibit  4.01EE to File No. 2-83364).                                                                                                                                                                                                                                      |
| 4.33*   |   | May 1, 1983 (Exhibit  4.01FF to File No. 2-97667).                                                                                                                                                                                                                                       |
| 4.34*   |   | Dec. 1, 1983 (Exhibit  4.01GG to File No. 2-97667).                                                                                                                                                                                                                                      |
| 4.35*   |   | Sept. 1, 1984 (Exhibit  4.01HH to File No. 2-97667).                                                                                                                                                                                                                                     |
| 4.36*   |   | Dec. 1, 1984 (Exhibit  4.01II to File No. 2-97667).                                                                                                                                                                                                                                      |
| 4.37*   |   | May 1, 1985 (Exhibit 4.36  to Form 10-K for the year 1985, File No. 001-03034).                                                                                                                                                                                                          |
| 4.38*   |   | Sept. 1, 1985 (Exhibit  4.37 to Form 10-K for the year 1985, File No. 001-03034).                                                                                                                                                                                                        |
| 4.39*   |   | July 1, 1989 (Exhibit 4.01  to Form 8-K dated July 7, 1989, File No. 001-03034).                                                                                                                                                                                                         |
| 4.40*   |   | June 1, 1990 (Exhibit 4.01  to Form 8-K dated June 1, 1990, File No. 001-03034                                                                                                                                                                                                           |
| 4.41*   |   | Oct. 1, 1992 (Exhibit 4.01  to Form 8-K dated Oct. 13, 1992, File No. 001-03034).                                                                                                                                                                                                        |
| 4.42*   |   | April 1, 1993 (Exhibit  4.01 to Form 8-K dated March 30, 1993, File No. 001-03034).                                                                                                                                                                                                      |
| 4.43*   |   | Dec. 1, 1993 (Exhibit 4.01  to Form 8-K dated Dec. 7, 1993, File No. 001-03034).                                                                                                                                                                                                         |
| 4.44*   |   | Feb. 1, 1994 (Exhibit 4.01  to Form 8-K dated Feb. 10, 1994, File No. 001-03034).                                                                                                                                                                                                        |
| 4.45*   |   | Oct. 1, 1994 (Exhibit 4.01  to Form 8-K dated Oct. 5, 1994, File No. 001-03034).                                                                                                                                                                                                         |
| 4.46*   |   | June 1, 1995 (Exhibit 4.01  to Form 8-K dated June 28, 1995, File No. 001-03034).                                                                                                                                                                                                        |
| 4.47*   |   | April 1, 1997 (Exhibit  4.47 to Form 10-K for the year 1997, File No. 001-03034).                                                                                                                                                                                                        |
| 4.48*   |   | March 1, 1998 (Exhibit  4.01 to Form 8-K dated March 11, 1998, File No. 001-03034).                                                                                                                                                                                                      |
| 4.49*   |   | May 1, 1999 (Exhibit 4.49  to Form 10 of NSP-Minnesota, File No. 000-31709).                                                                                                                                                                                                             |
| 4.50*   |   | June 1, 2000 (Exhibit 4.50  to Form 10 of NSP-Minnesota, File No. 000-31709).                                                                                                                                                                                                            |
| 4.51*   |   | Aug. 1, 2000 (Assignment  and Assumption of Trust Indenture) (Exhibit 4.51 to Form 10-12G (file no.  000-31709) dated Oct. 5, 2000).                                                                                                                                                     |
| 4.52*   |   | Trust Indenture, dated  July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and  Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated July 21, 1999).                                                   |
| 4.53*   |   | 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 Form 8-K (file no. 001-03034) dated July 21, 1999).                                      |
| 4.54*   |   | Supplemental Trust  Indenture dated Aug. 18, 2000, among Xcel Energy, Northern States Power Co.  (a Minnesota corporation) and Wells Fargo Bank Minnesota, National  Association, as Trustee. (Exhibit 4.63 to Form 10 (file no. 000-31709) dated  Oct. 5, 2000).                        |
| 4.55*   |   | Supplemental Trust  Indenture dated June 1, 2002, between Northern States Power Co. (a Minnesota  corporation) and BNY Midwest Trust Co., as successor trustee. (Exhibit 4.05  to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).                                                  |
| 4.56*   |   | Supplemental Trust  Indenture dated July 1, 2002, between Northern States Power Co. (a Minnesota  corporation) and BNY Midwest Trust Co., as successor trustee. (Exhibit 4.06  to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).                                                  |
| 4.57*   |   | Supplemental Trust  Indenture dated July 1, 2002, 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).                                    |
| 4.58*   |   | Supplemental Trust  Indenture dated Aug. 1, 2002, between Northern States Power Co. (a Minnesota  corporation) and BNY Midwest Trust Co., as Trustee. (Exhibit 4.01 to Form 8-K  (file no 000-31709) dated Aug. 22, 2002).                                                               |
| 4.59*   |   | 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).               |
| 4.60*   |   | 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 Xcel Energy Form 10-K (file no.  001-03034) dated March 15, 2004). |
| 4.61*   |   | Credit Agreement between  Northern States Power Company (a Minnesota corporation), Wells Fargo Bank,  National Association, Bank One NA and other financial institutions, dated May  14, 2004 (Exhibit 4.02 to Xcel Energy Form 10-Q (file no. 001-03034) filed  Aug. 4, 2004).          |
| 10.01*+ |   | Xcel Energy Omnibus  Incentive Plan (Exhibit A to Xcel Energy Form DEF-14A (file no. 001-03034)  filed Aug. 29, 2000).                                                                                                                                                                   |
| 10.02*+ |   | Xcel Energy Executive  Annual Incentive Award Plan (Exhibit B to Xcel Energy Form DEF-14A (file no.  001-03034) filed Aug. 29, 2000).                                                                                                                                                    |

 

63

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| 10.03*+ |   | Employment Agreement dated  March 24, 1999, among Northern States Power Co. (a Minnesota corporation),  New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New  Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).                                    |
|---------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.04*+ |   | Amended and Restated  Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to  NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31,  1998).                                                                                                                    |
| 10.05*+ |   | Stock Equivalent Plan for  Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct.  1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for  the year 1997).                                                                                            |
| 10.06*+ |   | Senior Executive Severance  Policy, effective March 24, 1999, between New Century Energies, Inc. and  Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q,  (File no. 001-12927) dated March 31, 1999).                                                                  |
| 10.07*+ |   | New Century Energies  Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A  (file no. 001-12927) filed March 26, 1998).                                                                                                                                                  |
| 10.08*+ |   | Directors’ Voluntary  Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K  (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                  |
| 10.09*+ |   | Supplemental Executive  Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K  (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                   |
| 10.10*+ |   | Salary Deferral and  Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New  Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                     |
| 10.11*+ |   | Salary Deferral and  Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century  Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                           |
| 10.12*+ |   | Supplemental Executive  Retirement Plan for Key Management Employees, as amended and restated March  26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (File no. 001-3280) dated Dec.  31, 1991).                                                                                                     |
| 10.13*+ |   | Form of Key Executive  Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4)  to PSCo Form 10-K (File no. 001-3280) dated Dec. 31, 1995).                                                                                                                             |
| 10.14*+ |   | Supplemental Retirement  Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (File  no. 001-03789) dated Aug. 31, 1996).                                                                                                                                                       |
| 10.15*+ |   | Xcel Energy Senior  Executive Severance and Change-in Control Policy dated Oct. 22, 2003 (Exhibit  10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).                                                                                                                            |
| 10.16*+ |   | Stock Equivalent Plan for  Non-employee Directors of Xcel Energy as amended and restated Jan. 1, 2004  (Exhibit B to Xcel Energy Form DEF-14A (file no. 001-03034) dated Apr. 9,  2004).                                                                                                         |
| 10.17*+ |   | Xcel Energy Nonqualified  Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy  Form 10-K (file no. 001-03034) dated March 15, 2004).                                                                                                                                     |
| 10.18*+ |   | Xcel Energy Inc.  Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel  Energy Form 10-K (file no. 001-03034) dated March 15, 2004).                                                                                                                                   |
| 10.19*+ |   | Xcel Energy 401(k) Savings  Plan, amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4  (file no. 333-112032) dated Jan. 21, 2004).                                                                                                                                            |
| 10.20*+ |   | New Century Energies, Inc.  Employee Investment Plan for Bargaining Unit Employees and Former  Non-bargaining Unit Employees, as amended and restated effective Jan. 1, 2002  but with certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file  no 333-112032) dated Jan. 21, 2004). |
| 10.21*  |   | Form of Services Agreement  between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Xcel  Energy Form U5B (file no. 001-03034) dated Nov. 16, 2000).                                                                                                                             |
| 10.22*  |   | Securities Litigation  Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit  10.01 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).                                                                                                                    |
| 10.23*  |   | ERISA Actions Settlement  Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.02 to  Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).                                                                                                                            |
| 10.24*  |   | Shareholder Derivative  Action Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005  (Exhibit 10.03 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14,  2005).                                                                                                           |
| 10.25*+ |   | Employment Agreement,  effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended  (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3,  2005).                                                                                                         |
| 10.26*+ |   | Compensation and  reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.26  to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                             |
| 10.27*+ |   | Xcel Energy executive  officer salaries, annual bonus targets and long-term compensation awards for  2005 (Exhibit 10.27 to Xcel Energy Form 10-K (file no. 001-03034) dated March  3, 2005).                                                                                                    |
| 10.28*+ |   | Amended Schedule of Participants  for Xcel Energy Senior Executive Severance and Change-in-Control Policy  (Exhibit 10.28 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3,  2005).                                                                                                   |
| 10.29*+ |   | Xcel Energy Executive  Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.29  to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                        |
| 10.30*+ |   | Xcel Energy Omnibus  Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.30 to Xcel  Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                                  |
| 10.31*+ |   | Xcel Energy Omnibus  Incentive Plan Form of Performance Share Agreement (Exhibit 10.31 to Xcel  Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                                      |
| 10.32*+ |   | Xcel Energy Omnibus  Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.32 to Xcel  Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                                  |
| 10.33*  |   | Facilities Agreement,  dated July 21, 1976, between Northern States Power Co. (a Minnesota  corporation) and the Manitoba Hydro-Electric Board relating to the  interconnection of the 500 kilovolt (KV) line. (Exhibit 5.06I to File No.  2-54310).                                             |
| 10.34*  |   | 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).                                                       |
| 10.35*  |   | 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).                                                       |

 

64

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| 10.36* |   | 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 (file no. 001-03034) for the quarter ended  Sept. 30, 1994). |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.37* |   | 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  (file no. 001-03034) for the quarter ended Sept. 30, 1994).                                    |
| 10.38* |   | Power Agreement, dated  August 1988, between Northern States Power Co. (a Minnesota corporation) and  Minnkota Power Co. (Exhibit 10.08 to Form 10-K (file no. 001-03034) for the  year 1988).                                                                                                                                                              |
| 10.39* |   | Assignment and Assumption  Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota  corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 (file no.  000-31709) dated Oct. 5, 2000)                                                                                                                                             |
| 10.40* |   | 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).                                                                          |
| 10.41* |   | 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).                                                                                              |
| 10.42* |   | 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).                                                                                                                                          |
| 10.43* |   | 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).                                                                                                                 |
| 10.44* |   | 500 megawatt System  Participation Power Sale Agreement dated July 30, 2002 between Northern  States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric  Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated  March 25, 2003).                                                                                       |
| 12.01  |   | Statement of Computation  of Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                                                                            |
| 23.01  |   | Consent of Independent Registered  Public Accounting Firm.                                                                                                                                                                                                                                                                                                  |
| 31.01  |   | Principal Executive  Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                |
| 31.02  |   | Principal Financial  Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                |
| 32.01  |   | Certification pursuant to  18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                   |
| 99.01  |   | Statement pursuant to  Private Securities Litigation Reform Act of 1995.                                                                                                                                                                                                                                                                                    |

 

65

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# **SCHEDULEII**

# ** **

**NSP-MINNESOTAVALUATION AND QUALIFYING ACCOUNTS AND RESERVESYears Ended Dec. 31, 2004, 2003 and 2002**

 

| ** **                            | ** ** | ** **                          | ** ** | **Additions**                         | ** ** | ** **                      | ** ** | ** **                        | ** ** |
|---------------------------------------|------------|-------------------------------------|------------|---------------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|
| ** **                            | ** ** | **Balance at beginning  of period** | ** ** | **Charged  to costs &  expenses** | ** ** | **Charged  to other  accounts** | ** ** | **Deductions  from  reserves(1)** | ** ** | **Balance  at end  of period** | ** ** |
| ** **                            | ** ** | **(Thousands of dollars)**          | ** ** |
| Reserve deducted from related assets: |       |                                |       |                                  |       |                            |       |                              |       |   |   |
| Provision for uncollectible accounts: |       |                                |       |                                  |       |                            |       |                              |       |   |   |
| 2004                                  |       | $                                   | 7,581      |                                  | $          | 15,688                          |       | $                                 | 4,077      |   | $ | 19,501 |   | $ | 7,845 |   |
| 2003                                  |       | $                                   | 5,812      |                                  | $          | 11,762                          |       | $                                 | 4,066      |   | $ | 14,059 |   | $ | 7,581 |   |
| 2002                                  |       | $                                   | 5,452      |                                  | $          | 8,028                           |       | $                                 | 4,197      |   | $ | 11,865 |   | $ | 5,812 |   |

 

----

(1)          Uncollectible accounts written off or transferred to other parties.

 

**Supplementalinformation to be furnished with reports filed pursuant to Section****15(d) ofthe Act by Registrants which have not registered securities in****pursuant to Section 12 of the Act.**

 

NSP-Minnesota has not sent,and does not expect to send, an annual report or proxy statement to itssecurity holder.

 

66

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**SIGNATURES**

 

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

 
| ** **         | **NORTHERN  STATES POWER COMPANY**                                                                 |
|--------------------|----------------------------------------------------------------------------------------------------|
|               |                                                                                               |
|               | /s/ BENJAMIN G.S. FOWKE  III                                                                       |   |
|               | Benjamin G.S. Fowke III  Vice President and Chief Financial Officer  (Principal Financial Officer) |
|               |                                                                                               |
| **March 3,  2005** |                                                                                               |

 

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report signed below by thefollowing persons on behalf of the registrant and in the capacities and on thedate indicated.

 
| /s/ WAYNE H. BRUNETTI                                                                              |                                                                                             | /s/ RICHARD C. KELLY |   |   |
|----------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------|----------------------|--------|--------|
| Wayne H.  Brunetti  Chief Executive Officer and Chairman  (Principal Executive Officer)            | Richard C. Kelly  President, Chief Operating Officer and Director  (Principal Operating Officer) |
|                                                                                               |                                                                                             |
| /s/ GARY R. JOHNSON                                                                                |                                                                                             | /s/ TERESA S. MADDEN |   |
| Gary R. Johnson  Vice President, General Counsel and Director                                      | Teresa S. Madden  Vice President and Controller  (Principal Accounting Officer)                  |
|                                                                                               |                                                                                             |
| /s/ BENJAMIN G.S. FOWKE  III                                                                       |                                                                                             |                 |
| Benjamin G.S. Fowke III  Vice President and Chief Financial Officer  (Principal Financial Officer) |                                                                                             |
|                                                                                                    |                                                                                                  |                      |        |        |  |

 

67

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