Northern States Power 10-K 2006 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                 to

COMMISSION FILE NUMBER 000-31387

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

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

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

o  Large accelerated filer    o  Accelerated filer    x Non-accelerated filer

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

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

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

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

INDEX

General Electric Utility Pending Regulatory Matters

Trading Operations

Nuclear Power Operations and Waste Disposal

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

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NMC	Nuclear Management Co., a company formed by NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corporation and Alliant Energy Corp.
NSP-Minnesota	Northern States Power Co., a Minnesota corporation
NSP-Wisconsin	Northern States Power Co., a Wisconsin corporation
PSCo	Public Service Company of Colorado, a Colorado corporation
SPS	Southwestern Public Service Co., a New Mexico corporation
utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy	Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
ASLB	Atomic Safety and Licensing Board
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas, and the sale of electricity at wholesale, in interstate commerce, including the sale of electricity at market-based rates.
MPUC	Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NDPSC	North Dakota Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in North Dakota.
NRC	Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
SDPUC	South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.
SEC	Securities and Exchange Commission
Fuel, Purchased Gas and Resource Adjustment Clauses
FCA	Fuel clause adjustment. A clause included in NSP-Minnesota’s retail electric rate schedules that provides for prospective monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.
PGA	Purchased gas adjustment. A clause included in NSP-Minnesota’s retail gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between the gas costs collected through PGA rates and the actual gas costs is collected or refunded over the subsequent 12-month period.
RCR	Renewable cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities and other costs incurred to facilitate the purchase of renewable energy (including wind energy) in retail electric rates in Minnesota. The RCR is revised annually.

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Other Terms and Abbreviations
AFDC	Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
ARO	Asset Retirement Obligation.
C20	Derivatives Implementation Group of FASB Implementation Issue No. C20. Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended.
decommissioning	The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
deferred energy costs	The amount of fuel costs applicable to service rendered in one accounting period that will not be reflected in billings to customers until a subsequent accounting period.
derivative instrument	A financial instrument or other contract with all three of the following characteristics: ·      An underlying and a notional amount or payment provision or both, ·      Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and ·      Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ERISA	Employee Retirement Income Security Act
FASB	Financial Accounting Standards Board
FTRs	Financial Transmission Rights
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
JOA	Joint operating agreement among the Utility Subsidiaries
LDC	Local distribution company. A company or division that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or natural gas for ultimate consumption.
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas. Natural gas that has been converted to a liquid.
mark-to-market	The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in current earnings in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.
MERP	Metropolitan emissions reduction project.
MGP	Manufactured gas plant.
MISO	Midwest Independent Transmission System Operator, Inc.
native load	The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas	A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
PFS	Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.

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PJM		PJM Interconnection, Inc.
PUHCA	Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies.
PUHCA 2005		Public Utility Holding Company Act of 2005. Successor to the Public Utility Holding Company Act of 1935.  Eliminates most federal regulation of utility holding companies.  Transfers other regulatory authority from the SEC to FERC.
QF		Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
ROE		Return on equity
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS		Statement of Financial Accounting Standards
SO2		Sulfur dioxide
TEMT		Transmission and Energy Markets Tariff
unbilled revenues		Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying		A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
VaR		Value-at-risk
wheeling or transmission		An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
working capital		Funds necessary to meet operating expenses
Measurements
Btu		British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
Bcf		Billion cubic feet
KV		Kilovolts
KW		Kilowatts
Kwh		Kilowatt hours
MMBtu		One million Btus
MW		Megawatts (one MW equals one thousand KW)
Mwh		Megawatt hour. One Mwh equals one thousand Kwh.
Watt		A measure of power production or usage equal to the kinetic energy of an object with a mass of 2 kilograms moving with a velocity of one meter per second for one second.

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COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota.  NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota.  The wholesale customers served by NSP-Minnesota comprised approximately 13 percent of the total sales in 2006.  NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.  NSP-Minnesota provides electric utility service to approximately 1.4 million customers and gas utility service to approximately 0.5 million customers.  Approximately 90 percent of NSP-Minnesota’s retail electric operating revenues was derived from operations in Minnesota during 2006.

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

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

ELECTRIC UTILITY OPERATIONS

Overview

Utility Industry Growth — NSP-Minnesota intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers.  NSP-Minnesota plans to continue to file rate cases with state and federal regulators to earn a return on its investment and recover costs of operations.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change.  Merger and acquisition activity has been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future.  The FERC has implemented wholesale electric utility competition, and the wholesale customers of Xcel Energy’s utility subsidiaries can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ use to serve their native load.  Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition.

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota.  State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 10 to the Consolidated Financial Statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act repealed PUHCA effective Feb. 8, 2006.  In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act.  Since Aug. 2005, the FERC has completed or initiated the proceedings to modify its regulations on a number of subjects, including:

·Adopting new regulations by establishing rules for accounting procedures for holding company systems, including cost allocation rules for transactions between companies within a holding company system;

·Adopting new regulations to implement changes to the FERC’s merger and asset transfer authority;

·Adopting new “market manipulation regulations” prohibiting any “manipulative or deceptive device or contrivance” in wholesale natural gas and electricity commodity and transportation or transmission markets and interpreting this standard in a manner consistent with Rule 10b-5 of the SEC; violations are subject to potential civil penalties of up to $1 million per day;

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

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

·Adopting rules to implement changes to the Public Utility Regulatory Policy Act to allow utility ownership of QFs and strengthening the thermal energy requirements for entities seeking to be QFs;

·Proposing rules that would allow a utility to seek to eliminate its mandatory QF power purchase obligation for utilities in organized wholesale energy markets such as MISO; and

·Adopting rules to establish incentives for investment in new electric transmission infrastructure.

NSP-Minnesota generally supports the regulations adopted or proposed by the FERC to date, but cannot predict the ultimate impact the new regulations will have on its operations or financial results.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO.  NSP-Minnesota is a member of the MISO.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.

Centralized Regional Wholesale Markets — The FERC rules require RTO’s to operate centralized regional wholesale energy markets.  The FERC required the MISO to begin operation of a “Day 2” wholesale energy market on April 1, 2005.  MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTR’s.  The Day 2 market is intended to provide more efficient generation dispatch over the 15 state MISO region.

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, property transfers, mergers and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV.

The MPUC is also empowered to select and designate sites for new power plants with a capacity of 50 MW or more and wind energy conversion plants with a capacity of five MW or more. It also designates routes for electric transmission lines with a capacity of 100 KV or more. No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over the need for certain generating and transmission facilities, and the siting and routing of certain new generation and transmission facilities in North Dakota and South Dakota, respectively.

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

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA that provides for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel, fuel related items and purchased energy.  NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction.  The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers.  With NSP-Minnesota’s participation in the MISO Day 2 market, questions were raised regarding the inclusion of certain MISO charges in the FCA.  However, in December 2006, the MPUC authorized FCA recovery of all MISO Day 2 charges, except certain administrative charges, which NSP-Minnesota is partially recovering in base rates and partially deferring for future recovery.  In general, capacity costs are not recovered through the FCA.  NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

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

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MERP Rider Regulation — In 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant.  All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion.  The MPUC also approved a rate rider to recover prudent costs of the projects from Minnesota customers beginning Jan. 1, 2006, including a rate of return on the construction work in progress.  The MPUC approval has a sliding ROE scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and a debt ratio of 51.5 percent) to incentivize NSP-Minnesota to control construction costs. At Dec. 31, 2006, the estimated ROE was 10.74 percent, based on construction progress to date.

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

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

Capacity and Demand

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

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

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

Energy Sources and Related Initiatives

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

Purchased Power — NSP-Minnesota has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity is the measure of the rate at which a particular generating source produces electricity.  Energy is a measure of the amount of electricity produced from a particular generating source over a period of time.  Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

NSP-Minnesota also makes short-term purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to comply with minimum availability requirements, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

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

The MPUC referred this matter to a contested case hearing to develop the facts and issues that must be resolved to act on Excelsior’s petition, including development of price information.  The contested case proceeding considered a 603 MW unit in phase I and a second 603 MW unit in phase II of Excelsior project.

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In 2006, NSP-Minnesota and other parties filed testimony in phase I of this proceeding.  The parties filed briefs in January 2007.  The ALJ is expected to make a recommendation to the MPUC on phase I later in the first quarter of 2007 and make a recommendation on phase II in August 2007.

NSP-Minnesota’s position in the proceeding is that the proposal (i) is inconsistent with our resource need, (ii) is not likely to be least-cost and is not in the public interest, (iii) shifts substantial risks to NSP-Minnesota and our ratepayers, (iv) presents a power purchase agreement that is inconsistent with industry standards in its allocation of risks and costs, (v) the proposal fails to satisfy the elements of the statutes under which it is proposed, and (vi) the proposal could result in significant adverse financial consequences.  NSP-Minnesota intends to request that all costs associated with the proposed power purchase agreement, if approved, will be recoverable in customer rates.

NSP System Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its proposed resource plan for the period 2005 through 2019.  The proposed plan identified needed resources and proposed processes for acquiring resources to meet those needs.  On July 28, 2006, the MPUC issued an order that, among other things:

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

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

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

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

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

On Oct. 18, 2006, the MPUC issued an order after reconsideration clarifying the Nov. 1, 2006, filing requirements and extending the filing requirement for the nuclear upgrades until Sept. 1, 2007, to accommodate scheduling and legislative review of the MPUC’s decision in the Monticello certificate of need proceeding.

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

Base Load Acquisition Proceeding — On Nov. 1, 2006, NSP-Minnesota filed a proposal with the MPUC for a purchase of  375 MW of capacity and energy from Manitoba Hydro for the period 2015-2025 and the purchase of 380 MW of wind energy to fulfill the base load need identified in the 2004 resource plan.  The proposal included a signed term sheet with Manitoba Hydro for and a process to acquire the wind energy through competitive bidding.  Alternative suppliers were entitled to submit competing proposals to the MPUC by Dec. 18, 2006.  An alternate supplier proposed a 375 MW share of a mine mouth lignite circulating fluidized bed plant located in North Dakota and 380 MW of wind energy generation, with an option for Xcel Energy ownership in both components.  The MPUC found both NSP-Minnesota’s proposal and the alternate proposal to be substantially complete and referred the matter to a contested case proceeding.

Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission 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 approving construction, subject to certain conditions.  The initial projected cost of the transmission upgrades was approximately $160 million.  The MPUC granted a routing permit for the first major transmission facilities in the development program in 2004.  The remaining route permit proceedings were completed in 2005.  In 2003, the MPUC also approved an RCR automatic adjustment mechanism that allows NSP-Minnesota to recover the revenue requirements associated with certain transmission investments for delivery of renewable energy resources.

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

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

Nuclear Power Operations and Waste Disposal — NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  See additional discussion regarding the nuclear generating plants at Note 12 to the Consolidated Financial Statements.

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

Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive waste generated within its borders.  Low-level radioactive waste from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Barnwell facility located in South Carolina (all classes of low-level waste) and at the Clive facility located in Utah (class A low-level substance only).  NSP-Minnesota has an annual contract with Barnwell, but is also able to utilize the Clive facility through various low-level waste processors.  NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

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

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants.  In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant.  In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state.  In 2003, the Minnesota Legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with the NRC expire in 2013 and 2014.  The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC.  It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage.  It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at Prairie Island, for a total of 29 casks.  In October 2006, the MPUC authorized an on-site storage facility and 30 casks at Monticello which will allow the plant to operate to 2030.  Their decision becomes effective June 1, 2007, unless the legislature takes action.  As of Dec. 31, 2006, there were 22 casks loaded and stored at the Prairie Island plant.

PFS — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel.  In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah.  On Feb. 28, 2006, the NRC commissioners issued the license for PFS, ending the 8-year effort to gain a license for the site.  The license is contingent on the condition that PFS must demonstrate that it has adequate funding before construction may begin.  In December 2005, the U.S. Supreme Court denied Utah’s petition for a writ of certiorari to hear an appeal of a lower court’s ruling on a series of state statutes aimed at blocking the storage and transportation of spent fuel to PFS.  Also in December 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel. In September 2006, the Department of the Interior issued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that  it was revoking its previous Conditional Approval of the site lease between PFS and the Skull Valley Indian tribe even though the conditions had been met.  The stated reasons were principally lack of progress at Yucca Mountain and lack of Bureau of Indian Affairs staff to monitor this activity.  Both findings are expected to be appealed.

Prairie Island Steam Generator Replacement — Prairie Island Unit 2 steam generators received required inspections during a scheduled 2005 outage.  Based on current rates of degradation and available repair processes, NSP-Minnesota plans to replace these steam generators in the 2013 regular refueling outage.  Due to the potential shortages in the world markets for materials and shop capabilities, NSP-Minnesota received Xcel Energy board approval in August 2006 to begin the process for long-lead time materials.

Nuclear Plant Re-licensing — Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014.  Montcello’s license renewal was approved by the NRC in November 2006, and the MPUC issued its approval in October 2006 allowing additional spent fuel storage.  Minnesota statutes provide that the MPUC decision becomes effective June 1, 2007, which allows the legislature the opportunity to review the MPUC action if considered appropriate.  Prairie Island has initiated the necessary plant assessments and aging analysis to support submittal of similar applications to the NRC and the MPUC, currently planned for submittal in early 2008.

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Nuclear Plant Power Uprates —  At the direction of the MPUC, NSP-Minnesota is pursuing capacity increases of all three units that will total approximately 250 MW, to be implemented, if approved, between 2009 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned for replacement during the refueling outage in 2013. Total capital investment for these activities is estimated to be approximately $1 billion between 2006 and 2015. NSP-Minnestoa plans to seek approval for an alternative recovery mechanism from customers of its nuclear costs.  NSP-Minnesota plans to submit the certificate of need for the Monticello uprate in the second quarter of 2007 and the certificate of need for the Prairie Island uprate in the third quarter of 2007.

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

Following consummation of these sale transacions, NSP-Minnesota will be the sole remaining member of the NMC.  NSP-Minnesota is evaluating the situation and is considering various alternatives, including transitioning  the NMC to a wholly owned subsidiary of Xcel Energy.  To facilitate implementation of this option, Xcel Energy plans are progressing to restructure the NMC to support a two-site organization, as well as reabsorb the adminstrative functions within Xcel Energy by the end of 2007.

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

Fuel Supply and Costs

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

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

*Includes refuse-derived fuel and wood

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

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

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of approximately 99 percent of 2007 coal requirements, 99 percent of 2008 coal requirements and 99 percent of 2009 coal requirements.  Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication.  The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment with multiple producers and countries to alleviate the current supply/demand imbalance.  Due to less availability in the world market for uranium, conversion and enrichment, NSP-Minnesota is working toward maintaining a strategic inventory level to decrease its exposure to supply limitations.

·Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2008, approximately 90 percent of the requirements for 2009, and approximately 32 percent of the requirements for 2010 through 2012 with no coverage of requirements for 2013 and beyond.  Contracts with additional uranium concentrate suppliers are currently in various stages of negotiations that are expected to provide a portion of the requirements through 2016.

·Current contracts for conversion services cover 100 percent of the requirements through 2009 and approximately 67 percent of the requirements from 2010 through 2012, with no coverage for 2013 and beyond.

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·Current enrichment services contracts cover 100 percent of 2007 and 2008 and approximately 96 percent of the 2009 requirements.  Approximately 50 percent of the 2010 through 2013 enrichment services requirements are currently covered with no coverage of requirements for 2014 and beyond.  These current contracts expire at varying times between 2009 and 2013.  Contracts with additional enrichment services suppliers are being investigated for coverage from 2010 and beyond.

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

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants.  Contracts for additional uranium are currently being negotiated that would provide additional supply requirements through 2016.  Some exposure to price volatility will remain, due to index-based pricing structures of the contracts.

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

Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products.  NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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NSP-Minnesota Electric Operating Statistics

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

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NATURAL GAS UTILITY OPERATIONS

Summary of Recent Regulatory Developments

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

Ratemaking Principles

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

Purchased Gas and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs are collected or refunded over the subsequent 12-month period. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

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

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

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).  The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 601,336 MMBtu for 2006, which occurred on Feb. 17, 2006.

NSP-Minnesota purchases natural gas from independent suppliers.  These purchases are generally priced based on market indices that reflect current prices.  The natural gas is delivered under natural gas transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of 526,013 MMBtu/day.  In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services.  These storage agreements provide storage for approximately 30 percent of winter natural gas requirements and 37 percent of peak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements.  These peak-shaving facilities have production capacity equivalent to 250,300 MMBtu of natural gas per day, or approximately 34 percent of peak day firm requirements.  LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

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

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates.  In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC.  This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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

2006	$	8.32
2005	$	8.90
2004	$	6.88

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

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2007 through 2027.

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

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 25 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

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

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NSP-Minnesota Natural Gas Operating Statistics

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

ENVIRONMENTAL MATTERS

Certain of NSP-Minnesota’s facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies.  NSP-Minnesota has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

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

EMPLOYEES

The number of full-time NSP-Minnesota employees on Dec. 31, 2006 was 2,595.  Of these full-time employees, 2,094, or 81 percent, are covered under collective bargaining agreements.  NSP-Minnesota full-time employees include 420 employees loaned to the NMC.  In addition, the NMC has 651 full-time employees of its own.  See Note 6 to the Consolidated Financial Statements for further discussion.  Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to NSP-Minnesota.

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Item 1A — Risk Factors

Risks Associated with Our Business

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

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

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

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including paying debt payments.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.  For example, Standard and Poor’s calculates an imputed debt associated with capacity payments from purchased power contracts.   An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard and Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings variability. We utilize quoted market prices to the maximum extent possible in determining the value of these derivative commodity instruments.  For positions for which market prices are not available, we utilize models based on forward price curves. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions could cause significant earnings variability.

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If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.

We are subject to interest rate risk.

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

We are subject to credit risks.

Credit risk includes the risk that counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

We are subject to environmental laws and regulations, compliance with which could be difficult and costly.

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

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

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

In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.  Revised or additional laws or regulations which result in increased compliance costs or additional operating restrictions, or currently unanticipated costs or restrictions under existing laws or regulations, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

For further discussion see Note 11 to the Consolidated Financial Statements.

Economic conditions could negatively impact our business.

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

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capital.

We are subject to the risks of nuclear generation.

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

•the risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

•limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

•uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

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

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

Our operations could be impacted by war, acts of terrorism or threats of terrorism.

The conflict in Iraq and any other military strikes or sustained military campaign may affect our operations in unpredictable ways and may cause disruptions of fuel supplies and markets, particularly with respect to natural gas and purchased energy.  War and the possibility of further war may have an adverse impact on the economy in general.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business.  While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.

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

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

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

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

Reduced coal availability could negatively impact our business.

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

Rising energy prices could negatively impact our business.

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

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

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

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

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

Increased risks of regulatory penalties could negatively impact our business

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

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

We have defined benefit and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  Therefore, our funding requirements may change and our contributions could be required in the future.

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

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

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As we are a subsidiary of Xcel Energy, if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternate sources of funds to meet our cash needs.

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets.  This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

As of Dec. 31, 2006, Xcel Energy had approximately $6.4 billion of long-term debt and $1.0 billion of short-term debt or current maturities.  Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.  Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2006, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $76.2 million and $17.5 million of exposure.  Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with these indemnities outstanding as of Dec. 31, 2006, was approximately $118.6 million.  Xcel Energy’s total exposure under these indemnities cannot be determined at this time.  If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

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

Item 1B — Unresolved SEC Staff Comments

None.

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Item 2 — Properties

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

Electric utility generating stations:

Station, City and Unit	Fuel	Installed	Summer 2006 Net Dependable Capability (MW)
Steam:
Sherburne-Becker, MN
Unit 1	Coal	1976	697
Unit 2	Coal	1977	682
Unit 3	Coal	1987	504	(a)
Prairie Island-Welch, MN
Unit 1	Nuclear	1973	551
Unit 2	Nuclear	1974	545
Monticello-Monticello, MN	Nuclear	1971	572
King-Bayport, MN	Coal	1968	528
Black Dog-Burnsville, MN
2 Units	Coal/Natural Gas	1955-1960	282
2 Units	Natural Gas	2002	298
High Bridge-St. Paul, MN
2 Units	Coal	1956-1959	271
Riverside-Minneapolis, MN
2 Units	Coal	1964-1987	381
Combustion Turbine:
Angus Anson-Sioux Falls, SD
3 Units	Natural Gas	1994-2005	384
Inver Hills-Inver Grove Heights, MN
6 Units	Natural Gas	1972	350
Blue Lake-Shakopee, MN
6 Units	Natural Gas	1974-2005	490
Other	Various	Various	169
		Total	6,704

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

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

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

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

Natural gas utility mains at Dec. 31, 2006:

	Miles
Transmission	120
Distribution	9,321

Item 3 — Legal Proceedings

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

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Nuclear Waste Disposal Litigation — The federal government has the responsibility to dispose of domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act (the Act) requires the DOE to implement this disposal program. This includes the siting, licensing, construction and operation of a permanent repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances.   The Act and contracts between the DOE and domestic utilities obligated the DOE to begin to dispose of these materials by Jan. 31, 1998.  The federal government has designated the site as Yucca Mountain in Nevada. The nuclear waste disposal program has resulted in extensive litigation.

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

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

On July 9, 2004, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to most of the NRC’s challenged repository licensing regulations, the congressional resolution approving Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the approval of the Yucca Mountain site. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal at Yucca Mountain and incorporated in the NRC regulations. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel. In July 2006 the Office of Civilian Radioactive Waste Management indicated that under the “best achievable repository construction schedule”, Yucca Mountain would be able to begin accepting spent nuclear fuel in March 2017.

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

Other Matters

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

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

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

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PART II

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

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

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

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

·Covenant restrictions under NSP-Minnesota’s credit agreement include a required debt to total capital ratio.

·State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota  can pay to Xcel Energy through requiring a minimum equity ratio of 45.99%.

The dividends declared during 2006 and 2005 were as follows:

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

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

Item 6 — Selected Financial Data

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

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

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

Forward Looking Information

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of NSP-Minnesota to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership, structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2006.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

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

Electric Utility, Short-Term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers, most fluctuations in energy costs do not materially affect electric utility margin.

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

Margins from commodity trading activity conducted at NSP-Minnesota are partially redistributed among PSCo and SPS, both wholly owned subsidiaries of Xcel Energy, pursuant to the JOA approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenues. Commodity trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs. Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.

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

	Base Electric Utility			Short-Term Wholesale			Commodity Trading			Consolidated Totals
	(Millions of Dollars)
2006
Electric utility revenue (excluding commodity trading)	$	3,084		$	178		$	—		$	3,262
Fuel and purchased power	(1,287		)	(159		)	—			(1,446		)
Commodity trading revenue	—			—			131			131
Commodity trading costs	—			—			(128		)	(128		)
Gross margin before operating expenses	$	1,797		$	19		$	3		$	1,819
Margin as a percentage of revenue	58.3		%	10.7		%	2.3		%	53.6		%
2005
Electric utility revenue (excluding commodity trading)	$	2,828		$	177		$	—		$	3,005
Fuel and purchased power	(1,227		)	(103		)	—			(1,330		)
Commodity trading revenue	—			—			143			143
Commodity trading costs	—			—			(137		)	(137		)
Gross margin before operating expenses	$	1,601		$	74		$	6		$	1,681
Margin as a percentage of revenue	56.6		%	41.8		%	4.2		%	53.4		%

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

Base Electric Revenue

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

Base Electric Margin

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

Certain transmission expenses related to purchase power are reported as a component of base electric margin in 2006, compared with the 2005 presentation as a component of operating and maintenance expense, which served to lower electric margin by $22 million for the year, with no impact on operating or net income.

Short-term wholesale and commodity trading margins decreased $58 million in 2006, compared with 2005. As expected, short-term margins declined due to retail sales growth, which reduced surplus generation available for sale in the wholesale market, and decreased opportunities to sell due to the MISO centralized dispatch market.

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

Natural Gas Utility Margins — The following table details the change in natural gas revenue and margin. The cost of natural gas tends to vary with changing 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 gas margin.

(Millions of dollars)	2006			2005
Natural gas utility revenue	$	745		$	822
Cost of natural gas purchased and transported	(590		)	(665		)
Natural gas utility margin	$	155		$	157

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

Natural Gas Revenue

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

Natural gas revenue decreased primarily due to lower natural gas costs in 2006, which are recovered from customers.  Retail natural gas weather-normalized sales declined when compared to 2005, largely due to declining use per customer.

Natural Gas Margin

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

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

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

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

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

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

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Income tax expense increased by approximately $15.8 million in 2006, compared with 2005.  The increase in tax expense was primarily due to an increase in pretax income, which was partially offset by the reversal of a $9.8 million regulatory reserve in 2006 and by recognition of research and experimentation credits and net operating loss carry back claims of $6.7 million in 2005. The effective tax rate was 31.9 percent for 2006, compared with 32.0 percent for 2005.  Without the additional tax benefits, the effective tax rate would have been 34.4 percent for 2006 and 33.9 percent in 2005.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

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

Short-Term Wholesale and Commodity Trading Risk — NSP Minnesota conducts various short-term wholesale and commodity trading activities, including the purchase and sale of capacity, energy and energy-related instruments. These marketing activities generally have terms of less than one year in length. NSP Minnesota’s risk-management policy allows management to conduct these activities within guidelines and limitations as approved by the Company’s risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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

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

NSP-Minnesota’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. NSP-Minnesota utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas.

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

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

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

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

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

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NSP-Minnesota may engage in hedges of cash flow exposure.  The fair value of interest rate swaps designated as cash flow hedges is initially recorded in Other Comprehensive Income.  Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument, and generally offsets the change in the interest accrued on the underlying variable rate debt.  Hedges of fair value exposure are entered into to hedge the fair value of debt instruments.  Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of debt instruments.  To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis.  The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes.  There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

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

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

Credit Risk — In addition to the risks discussed previously, NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

NSP-Minnesota conducts standard credit reviews for all counterparties. NSP-Minnesota employs additional credit risk control mechanisms, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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Item 8 — Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder
Northern States Power Company—Minnesota

We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company—Minnesota and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, common stockholder’s equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2006.  Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that 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 Power Company—Minnesota and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 6 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” as of December 31, 2006.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2007

30

NSP-MINNESOTACONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)

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

See Notes to Consolidated Financial Statements

31

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

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

See Notes to Consolidated Financial Statements

32

NSP-MINNESOTA
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)

	Dec. 31, 2006			Dec. 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	16,019		$	38,542
Notes receivable from affiliates	30,300			64,000
Accounts receivable — net of allowance for bad debts: $13,408 and $10,128, respectively	370,635			398,678
Accounts receivable from affiliates	32,936			53,414
Accrued unbilled revenues	220,034			258,028
Materials and supplies inventories — at average cost	93,183			94,395
Fuel inventory — at average cost	40,257			33,609
Natural gas inventory — at average cost	85,016			83,977
Derivative instruments valuation	62,211			107,786
Prepayments and other	50,381			34,602
Total current assets	1,000,972			1,167,031
Property, plant and equipment, at cost:
Electric utility plant	8,245,632			8,018,167
Natural gas utility plant	859,533			829,522
Construction work in progress	917,275			496,884
Common utility and other property	416,635			467,215
Total property, plant and equipment	10,439,075			9,811,788
Less accumulated depreciation	(4,590,719		)	(4,454,408		)
Nuclear fuel — net of accumulated amortization: $1,237,917 and $1,190,386, respectively	140,152			102,409
Net property, plant and equipment	5,988,508			5,459,789
Other assets:
Nuclear decommissioning fund investments	1,200,688			1,047,592
Regulatory assets	372,349			450,200
Prepaid pension asset	276,571			379,808
Derivative instruments valuation	181,616			198,044
Other investments	30,892			37,331
Other	27,452			51,589
Total other assets	2,089,568			2,164,564
Total assets	$	9,079,048		$	8,791,384
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	40		$	204,833
Short-term debt	89,000			¾
Accounts payable	468,727			379,950
Accounts payable to affiliates	39,139			60,419
Taxes accrued	126,104			123,384
Accrued interest	48,308			49,122
Dividends payable to parent	56,105			54,613
Derivative instruments valuation	36,167			93,544
Other	38,572			57,852
Total current liabilities	902,162			1,023,717
Deferred credits and other liabilities:
Deferred income taxes	708,772			821,417
Deferred investment tax credits	47,654			52,500
Asset retirement obligations	1,311,271			1,242,919
Regulatory liabilities	658,571			846,195
Derivative instruments valuation	248,981			246,951
Pension and employee benefit obligations	209,548			93,827
Other liabilities	69,229			55,922
Total deferred credits and other liabilities	3,254,026			3,359,731
Commitments and contingent liabilities (see Note 11)
Capitalization (see Statements of Capitalization):
Long-term debt	2,299,188			2,155,540
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10			10
Additional paid in capital	1,561,480			1,247,624
Retained earnings	1,055,983			1,004,762
Accumulated other comprehensive income	6,199			¾
Total common stockholder’s equity	2,623,672			2,252,396
Total liabilities and equity	$	9,079,048		$	8,791,384

See Notes to Consolidated Financial Statements

33

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME
(Dollars in Thousands)

	Common Stock				Additional Paid		Retained			Accumulated Other Comprehensive			Total Stockholder’s
	Shares	Amount			in Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2003	1,000,000	$	10		$	842,969	$	965,880		$	(4	)	$	1,808,855
Net income							230,274						230,274
Net derivative instrument fair value changes during the period, net of tax of $(2)										4			4
Comprehensive income for 2004													230,278
Common dividends declared to parent							(212,214		)				(212,214		)
Contribution of capital by parent					180,408								180,408
Balance at Dec. 31, 2004	1,000,000	$	10		$	1,023,377	$	983,940		$	—		$	2,007,327
Net income							237,744						237,744
Net derivative instrument fair value changes during the period										—			—
Comprehensive income for 2005													237,744
Common dividends declared to parent							(216,922		)				(216,922		)
Contribution of capital by parent					224,247								224,247
Balance at Dec. 31, 2005	1,000,000	$	10	��	$	1,247,624	$	1,004,762		$	—		$	2,252,396
Net income							272,310						272,310
Net derivative instrument fair value changes during the period, net of tax of $6,513										9,433			9,433
Comprehensive income for 2006													281,743
SFAS No. 158 adoption, net of tax of $(2,233) (see Note 6)										(3,234		)	(3,234		)
Common dividends declared to parent							(221,089		)				(221,089		)
Contribution of capital by parent					313,856								313,856
Balance at Dec. 31, 2006	1,000,000	$	10		$	1,561,480	$	1,055,983		$	6,199		$	2,623,672

See Notes to Consolidated Financial Statements

34

NSP-MINNESOTACONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

	Dec. 31
	2006			2005
Long-Term Debt
First Mortgage Bonds, Series due:
Dec. 1, 2006, 4.1% (a)	$	—		$	2,420
Dec. 1, 2007-2008, 4.5%-4.6% (a)	—			7,490
Aug. 1, 2006, 2.875%	—			200,000
Aug. 1, 2010, 4.75%	175,000			175,000
Aug. 28, 2012, 8%	450,000			450,000
March 1, 2019, 8.5% (b)	27,900			27,900
Sept. 1, 2019, 8.5% (b)	100,000			100,000
July 1, 2025, 7.125%	250,000			250,000
March 1, 2028, 6.5%	150,000			150,000
April 1, 2030, 8.5% (b)	69,000			69,000
July 15, 2035, 5.25%	250,000			250,000
June 1, 2036, 6.25%	400,000			—
Senior Notes due Aug. 1, 2009, 6.875%	250,000			250,000
Borrowings under credit facility, due April 2010, 5.05%	—			250,000
Retail Notes due July 1, 2042, 8%	185,000			185,000
Other	89			841
Unamortized discount	(7,761		)	(7,278		)
Total	2,299,228			2,360,373
Less current maturities	40			204,833
Total long-term debt	$	2,299,188		$	2,155,540
Common Stockholder’s Equity
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2006 and 2005	$	10		$	10
Additional paid in capital	1,561,480			1,247,624
Retained earnings	1,055,983			1,004,762
Accumulated other comprehensive income	6,199			—
Total common stockholder’s equity	$	2,623,672		$	2,252,396

(a)Resource recovery financing

(b)Pollution control financing

See Notes to Consolidated Financial Statements

35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

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

Principles of Consolidation — NSP-Minnesota has subsidiaries, which have been consolidated and for which all significant intercompany transactions and balances have been eliminated.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy 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 each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.

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

·NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.  The electric cost-of-fuel-and-purchased-energy mechanism also provides a sharing among shareholders and customers of certain margins on short-term wholesale sales and commodity trading.

·NSP-Minnesota operates under various service quality standards which could require customer refunds if certain criteria are not met. NSP-Minnesota’s rates also include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually.  NSP-Minnesota is allowed to recover certain costs associated with new transmission facilities to deliver renewable energy resources through a rate rider.

·NSP-Minnesota sells firm power and energy in wholesale markets, which are regulated by the FERC. Certain of these rates include monthly wholesale fuel cost-recovery mechanisms.

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

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

Derivative Financial Instruments — NSP-Minnesota utilizes a variety of derivatives, including commodity forwards, futures and options, index or fixed price swaps and basis swaps to mitigate market risks and to enhance its operations.  For further discussion of NSP-Minnesota’s risk management and derivative activities, see Note 8 to the Consolidated Financial Statements.

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

36

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

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

Generally AFDC costs are recovered from customers as the related property is depreciated. In December 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion. The MPUC has approved a more current recovery of the financing costs related to the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFDC.

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

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

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

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

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

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

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

37

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Minnesota uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, asset retirement obligations, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.

Cash and Cash Equivalents — NSP-Minnesota considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Inventory — All inventory for NSP-Minnesota is recorded at average cost.

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

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

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

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.

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

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

Accounts Receivable and Allowance for Uncollectibles — Accounts receivable are stated at the actual billed amount net of the allowance for uncollectibles.  NSP-Minnesota establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the Federal EPA.  We follow the inventory model for all allowances.  The sales of allowances are reported in the Operating Activities section of the Consolidated Statements of Cash Flows.  The net margin on sales of emission allowances is included in Operationing Revenue as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

Reclassifications — The balance sheet and the statements of cash flows have been reclassified from prior-period presentation to conform to the 2006 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were related to the presentation of regulatory assets and liabilities for ARO and decommissioning activities on a net basis.  These reclassifications did not affect total operating, investing or financing within the statements of cash flows.

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

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

38

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

2.Short-Term Borrowings

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

Money Pool - Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals.  Approval was also granted by the FERC in a July 18, 2006 order.  The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company.  NSP-Minnesota has approval to borrow up to $250 million under the arrangement.  NSP-Minnesota had no borrowings or loans outstanding under the arrangement at Dec. 31, 2006.

3.Long-Term Debt

Credit Facilities — At Dec. 31, 2006, NSP-Minnesota had the following committed credit facility in effect, in millions of dollars:

	Credit Facility
Credit Facility	Borrowings	Available*	Term	Maturity
$500	$—	$376.5	Five year	December 2011

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

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  NSP-Minnesota has the right to request an extension of the final maturity date by one year.  The maturity extension is subject to majority bank group approval.  The credit facility has one financial covenant requiring that NSP-Minnesota’s debt to total capitalization ratio be less than or equal to 65 percent with which NSP-Minnesota was in compliance at Dec. 31, 2006.  The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by NSP-Minnesota’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch.

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

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

Maturities of long-term debt are:

(Millions of Dollars)
2007	$	—
2008	$	—
2009	$	250.0
2010	$	175.0
2011	$	—

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4. Joint Plant Ownership

Following are the investments by NSP-Minnesota in jointly owned plants and the related ownership percentages as of Dec. 31, 2006:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
Sherco Unit 3	$	496,188	$	293,906	$	2,130	59.0
Sherco Common Facilities Units 1, 2 & 3	106,939		57,800		2,292		75.0
Transmission facilities, including substations	4,832		2,004		—		59.0
Total	$	607,959	$	353,710	$	4,422

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

5.   Income Taxes

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

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

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

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

The components of deferred income tax at Dec. 31 were:

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

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

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

6.   Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

Xcel Energy offers various benefit plans to its benefit employees, including those of NSP-Minnesota.  Approximately 56 percent of Xcel Energy benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2006, NSP-Minnesota had 2,094 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007.

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income.  The following table shows the impact of the implementation on the consolidated statement of financial position.  NSP-Minnesota applied regulatory accounting treatment, which allowed recognition of this item as a regulatory liability reduction rather than as a charge to accumulated other comprehensive income.  The table reflects the deferral of these amounts as reductions to regulatory liabilities.The table also includes noncontributory, defined benefit supplemental retirement income plans.

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

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Pension Benefits

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

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

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

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

	2006		2005
Equity securities	63	%	65	%
Debt securities	22		20
Real estate	4		4
Cash	2		1
Nontraditional investments	9		10
	100	%	100	%

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 11.3 percent, which is greater than the current assumption level. The pension cost determination assumes the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments that can provide a higher-than-average return.  A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2006, 2005 and 2004 exceeded the assumed level of 8.75, 8.75 and 9.0 percent, respectively.  Xcel Energy continually reviews its pension assumptions.  In 2007, Xcel Energy will continue to use an investment-return assumption of 8.75 percent.

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

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

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2004 through 2006 for Xcel Energy’s pension plans, and are not expected to require cash funding in 2007.

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

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Benefit Costs — The components of net periodic pension cost (credit) are:

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

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2007 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

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

Defined Contribution Plans

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

Postretirement Health Care Benefits

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

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

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

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

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

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

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

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

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

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

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

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Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent.  The period until the ultimate rate is reached also was increased from two years to six years.  Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

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

(Millions of Dollars)
1-percent increase in APBO components at Dec. 31, 2006	$	21.9
1-percent decrease in APBO components at Dec. 31, 2006	(18.3		)
1-percent increase in service and interest components of the net periodic cost	1.6
1-percent decrease in service and interest components of the net periodic cost	(1.3		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $61 million during 2007.

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

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

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Projected Benefit Payments

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

7.   Detail of Interest and Other Income — Net

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

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

8.   Derivative Instruments

In the normal course of business, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  NSP-Minnesota utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.  The use of these derivative instruments is discussed in further detail below.

Utility Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in their electric and natural gas operations.  Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and other energy-related products, and for various fuels used in the generation of electricity and natural gas utility operation.  Commodity risk also is managed through the use of financial derivative instruments.  NSP-Minnesota utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of our retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs.  In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost-recovery mechanism.  NSP-Minnesota’s risk-management policy allows it to manage market price risk to the extent such exposure exists.

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

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

Types of and Accounting for Derivative Instruments

NSP-Minnesota uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship.  The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance.  This classification is dependent on the applicability of specific regulation.  This includes certain instruments used to mitigate market risk for NSP-Minnesota and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective.  The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.

SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.  NSP-Minnesota formally documents hedging relationships, including, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk-management objectives and strategies for undertaking the hedged transaction.  NSP-Minnesota also formally assesses, both at inception and on an ongoing basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs;  hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; and interest rate hedging transactions are recorded as a component of interest expense.  NSP-Minnesota is allowed to recover in natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.

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

Cash Flow Hedges

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

Commodity Cash Flow Hedges — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices.  These derivative instruments are designated as cash flow hedges for accounting purposes.  At Dec. 31, 2006, NSP-Minnesota had various commodity-related contracts classified as cash flow hedges extending through November 2007.  The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability.  This classification is based on the regulatory recovery mechanism in place.  Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled.  This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or natural gas purchased for resale.

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

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

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

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

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on NSP-Minnesota’s Accumulated Other Comprehensive Income, included in the Consolidated Statements of Stockholder’s Equity, is detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive income related to hedges at Dec. 31, 2003	$	—
After-tax net unrealized losses related to derivatives accounted for as hedges	(0.7		)
After-tax net realized losses on derivative transactions reclassified into earnings	0.7
Accumulated other comprehensive income related to hedges at Dec. 31, 2004	$	—
After-tax net unrealized gains related to derivatives accounted for as hedges	—
After-tax net realized gains on derivative transactions reclassified into earnings	—
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	—
After-tax net unrealized gains related to derivatives accounted for as hedges	9.6
After-tax net realized gains on derivative transactions reclassified into earnings	(0.2		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2006	$	9.4

Normal Purchases or Normal Sales Contracts

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

NSP-Minnesota evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133.  None of the contracts entered into within the commodity trading operations qualify for a normal designation.

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

Normal purchases and normal sales contracts are accounted for as executory contracts.

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

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

For a further discussion of other financial instruments at NSP-Minnesota, see Note 9 to the Consolidated Financial Statements.

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9.   Financial Instruments

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

	2006				2005
(Thousands of Dollars)	Carrying  Amount		Fair Value		Carrying  Amount		Fair Value
Nuclear decommissioning fund	$	1,200,688	$	1,200,688	$	1,047,592	$	1,047,592
Other investments	$	10,415	$	10,415	$	2,544	$	2,544
Long-term debt, including current portion	$	2,299,228	$	2,466,465	$	2,360,373	$	2,549,257

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

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

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

(Thousands of Dollars)	2006		2005		2004
Realized gains	$	310,066	$	8,967	$	16,578
Realized losses	$	32,412	$	8,990	$	20,180
Proceeds from sale of securities	$	1,240,034	$	489,697	$	223,135

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

Letters of Credit

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

10. Rate Matters

Pending and Recently Concluded Regulatory Proceedings - FERC

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

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

Within MISO, an independent market monitor (IMM) reviews market bids and prices to identify any unusual activity.  NSP-Minnesota and other market participants continue to work with MISO, the IMM and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details.

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

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additional proceedings.  Various parties filed requests for rehearing.  On Nov. 29, 2006, the FERC issued an order on rehearing upholding the February 2006 order and approving the 20 percent limitation.

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

Transmission service rates in the MISO region presently use a rate design, in which the transmission cost depends on the location of the load being served.  Costs of existing transmission facilities are not regionalized.  MISO is required to file a replacement rate methodology in August 2007, to be effective Feb. 1, 2008.  It is possible MISO will propose to regionalize the recovery of the costs of existing transmission facilities.  Proposals to regionalize transmission costs could shift the costs of NSP-Minnesota transmission investments to other MISO transmission service customers, but would also shift the costs of transmission investments in other parts of MISO to NSP-Minnesota.

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

The competing SECA compliance proposals were the subject of litigated hearings at the FERC.  Certain parties proposed a regional average SECA charge, which could shift costs to NSP-Minnesota and NSP-Wisconsin.  On Aug. 10, 2006, the ALJ in the case issued an initial decision recommending that all the SECA compliance filings be rejected and recommending adoption of a regional SECA, which could shift approximately $13 million in charges to NSP-Minnesota and NSP-Wisconsin.  Xcel Energy, through the MISO transmission owners, filed exceptions to the ALJ initial decision, arguing the decision directly violates the 2004 FERC orders.  In addition, the MISO transmission owners have executed settlements with several parties in the litigation.  The settlement resolves specific claims and would limit any regionalization to unresolved claims.  Final FERC action is expected in the SECA litigation in 2007.

Revenue Sufficiency Guarantee Charges — On April 25, 2006, the FERC issued an order determining that MISO had incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are collected from certain MISO customers and paid to others. Based on the FERC order, NSP-Minnesota could be required to make net payments to MISO. On Oct. 26, 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds and ordered MISO to implement prospective changes.  In late November 2006, however, certain parties filed further requests for rehearing challenging the reversal regarding refunds.  The date of a final FERC decision is unknown, and one appeal has been filed.  Xcel Energy reserved $6.1 million in response to the April 25, 2006, FERC order.

Pending and Recently Concluded Regulatory Proceedings- MPUC

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

On Sept. 1, 2006, the MPUC issued a written order granting an electric revenue increase of approximately $131 million for 2006 based on an authorized return on equity of 10.54 percent. The scheduled rate increase will be reduced in 2007 to $115 million to reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system.  The MPUC approved the wholesale margin settlement in which NSP-Minnesota returns most margins from unused generating capacity back to customers through the FCA mechanism.  NSP-Minnesota is allowed to earn an incentive on sales related to ancillary service obligations.  The MPUC Order became effective in November 2006, and final rates were implemented on February 1, 2007.  A citizen intervenor has appealed the MPUC’s decision.

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

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

Renewable Transmission Cost Recovery — Since December 2004, NSP-Minnesota has recovered certain transmission costs related to wind generation projects through a RCR rider.  In November 2006, the MPUC approved the replacement of the RCR rider with a TCR rider pursuant to 2005 legislation.  The TCR mechanism would allow recovery of incremental transmission investments between rate cases.  On Oct. 27, 2006, NSP-Minnesota filed for approval of recovery of $14.8 million in 2007 revenue requirements under the TCR tariff.  Final MPUC action is expected later in the first quarter of 2007.  The RCR rate factors will remain in effect until the TCR factors are implemented.

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

In March 2005, NSP-Minnesota filed petitions similar to the December 2004 Minnesota filing with the NDPSC and the SDPUC proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of the MISO Day 2 market costs.  The SDPUC approved the proposed tariff changes, effective April 1, 2005, as requested.  The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but conditioned the relief as being subject to refund until the merits of the case are determined.  Since April 1, 2005, NSP-Minnesota has collected approximately $28 million of MISO Day 2 charges through its North Dakota FCA.

11. Commitments and Contingent Liabilities

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

CAPX 2020 — In June 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified three groups of transmission projects that proposed to be complete by 2020.  Group 1 project investments are expected to total approximately $1.3 billion, with major construction targeted to begin in 2009 or 2010 and ending three or four years later. Xcel Energy’s investment is expected to be approximately $700 million. Approximately 75 percent of the capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota transmission cost recovery tariff rider mechanism authorized by Minnesota legislation and pending MPUC approval. Similar transmission cost recovery mechanisms have been proposed in North Dakota and South Dakota.

Nuclear Capacity Increases and Life Extension — In August 2004, NSP-Minnesota announced plans to pursue 20-year license renewals for the Monticello and Prairie Island nuclear plants, whose licenses will expire between 2010 and 2014. License renewal applications for Monticello were submitted to the NRC and the MPUC in early 2005. License renewal was approved by the NRC in November 2006, and the MPUC issued its approval in October 2006 allowing additional spent fuel storage. The MPUC stayed the order until June 2007, following the Minnesota legislative session. Similar applications will be submitted for Prairie Island in 2008, with approval expected in 2010.

At the direction of the MPUC, NSP-Minnesota is pursuing capacity increases of all three units that will total approximately 250 MW, to be implemented, if approved, between 2009 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned for replacement during the refueling outage in 2013. Total capital investment for these activities is estimated to be approximately $1 billion between 2006 and 2015. Xcel Energy plans to seek approval for an alternative recovery mechanism from customers of its nuclear costs.  It is NSP-Minnesota’s plan to submit the certificate of need for Monticello in the second quarter of 2007 and the certificate of need for Prairie Island in the third quarter of 2007.

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

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

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

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

The capital expenditure programs of NSP-Minnesota are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting NSP-Minnesota’s long-term energy needs. In addition, NSP-Minnesota’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

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

Future commitments under noncancellable operating leases with terms in excess of one year are:

(Millions of Dollars)
2007	$	36.6
2008	$	35.0
2009	$	35.2
2010	$	33.9
2011	$	32.8
Thereafter	$	480.1

Fuel Contracts — NSP-Minnesota has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2007 and 2027. In addition, NSP-Minnesota may be required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.

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

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

Purchased Power Agreements — NSP-Minnesota has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indices.  However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

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

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

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

Environmental Contingencies

NSP-Minnesota has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense.

Site Remediation — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota and some other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including the following categories of sites:

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

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

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

To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known.  At Dec. 31, 2006, the liability for the cost of these remediating sites was estimated to be $1.1 million, of which $0.3 million was considered to be a current liability.  Some of the cost of remediation may be recovered from:

·insurance coverage;

·other parties that have contributed to the contamination; and

·customers.

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

Third Party and Other Environmental Site Remediation

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

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asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Clean Air Interstate Rule — In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR) to further regulate SO2 and nitrogen oxide (NOx) emissions.  The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota.  CAIR addresses the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states.  CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOX that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap-and-trade program.   State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

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

On June 13, 2006, the MPCA issued a draft rule for implementing the CAIR in Minnesota, which further regulates SO2 and NOx emissions. This proposal would require more stringent emission reductions than the federal CAIR program, resulting in additional implementation costs. The MPCA has stated publicly that it is revising its proposal such that the federal CAIR program will be implemented for 2009 and that the MPCA is considering a rulemaking process to require more stringent emission reductions than the federal CAIR program for subsequent years. Approval to commence this rulemaking is expected in 2007.

While NSP-Minnesota expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives.  Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time.  The EPA’s CAMR  uses a national cap-and-trade system, where compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to achieve a 70 percent reduction in mercury emissions.  It affects all coal- and oil-fired generating units across the country that are greater than 25 MW.  Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018.  States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states.  Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state.  Similar to CAIR, states can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

NSP-Minnesota continues to evaluate the strategy for complying with CAMR. NSP-Minnesota can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances.  NSP-Minnesota’s preliminary analysis for phase I compliance suggests capital costs of approximately $10.3 million for the mercury control equipment and continuous monitoring equipment and increased operating and maintenance expenses of approximately $4.8 million, beginning in 2010. These costs are included in the estimated costs of compliance with the Minnesota Mercury Legislation described below.  Additional costs will be incurred to meet phase II requirements in 2018.

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

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maintenance expenses of approximately $11.3 million, beginning in 2010.  Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. On Sept. 15, 2006, NSP-Minnesota filed a request with the MPUC for deferred accounting of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act.  On Jan. 11, 2007, the MPUC approved this request for deferred accounting with a cap of $6.3 million.

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.

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

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

Federal Clean Water Act —The federal Clean Water Act requires the EPA to regulate cooling water intake structures  to assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking.  On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration. It is unclear whether the EPA will stay the deadlines in the rule until the remanded rulemaking is finished.  As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.

Asset Retirement Obligations

NSP-Minnesota records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with SFAS No. 143 — “Accounting for Asset Retirement Obligations” (SFAS No. 143). This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

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

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

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For the nuclear assets, the ARO associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originates with the in-service date of the facility.  Monticello began operation in 1971.  Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively.  See Note 12 to the Consolidated Financial Statements for further discussion of nuclear obligations.

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

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2006 and Dec. 31, 2005, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2006		Liabilities Recognized		Liabilities Settled			Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2006
Electric Utility Plant:
Steam production asbestos	$	21,719	$	—	$	—		$	1,229	$	(779	)	$	22,169
Steam production ash containment	16,887		—		—			933		(657		)	17,163
Steam production retirement	3,152		—		(3,309		)	157		—			—
Nuclear production decommissioning	1,184,968		—		—			71,795		—			1,256,763
Electric transmission and distribution	1,100		—		—			29		(189		)	940
Gas Utility Plant:
Gas transmission and distribution	12,059		—		—			299		20			12,378
Common Utility and Other Property:
Common general plant asbestos	3,034		—					162		(1,338		)	1,858
Total liability	$	1,242,919	$	—	$	(3,309	)	$	74,604	$	(2,943	)	$	1,311,271

(Thousands of Dollars)	Beginning Balance Jan. 1, 2005		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates		Ending Balance Dec. 31, 2005
Electric Utility Plant:
Steam production asbestos	$	—	$	3,890	$	—	$	17,829	$	—	$	21,719
Steam production ash containment	—		3,953		—		12,934		—		16,887
Steam production retirement	3,002		—		—		150		—		3,152
Nuclear production decommissioning	1,088,087		—		—		70,736		26,145		1,184,968
Electric transmission and distribution	—		1,100		—		—		—		1,100
Gas Utility Plant:
Gas transmission and distribution	—		12,059		—		—		—		12,059
Common Utility and Other Property:
Common general plant asbestos	—		575				2,459		—		3,034
Total liability	$	1,091,089	$	21,577	$	—	$	104,108	$	26,145	$	1,242,919

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

Removal Costs — NSP-Minnesota accrues an obligation for plant removal costs for generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO removal obligations is not required.  However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of

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

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

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $26.1 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

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

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota.  MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March and April of 2006. The parties entered into meaningful settlement negotiations in May 2006, and in August 2006 reached an oral settlement of the dispute.  The parties are negotiating over the final form of the settlement documents and it is expected that the action will be formally dismissed in the near future.

Siewert  vs. Xcel Energy — Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-Minnesota alleging negligence in the handling, supplying, distributing, and selling of electrical power systems, negligence in the construction and maintenance of distribution systems, and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production, injury and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs’ expert report on the economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million.  Trial is scheduled to commence in January 2008.  NSP-Minnesota denies these allegations and will vigorously defend itself in this matter.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions.  Although NSP-Minnesota is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on NSP-Minnesota.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or natural gas-fired power plants.  The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president.  On Sept. 19,

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2005, the judge granted the defendants’ motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the Second Circuit Court of Appeals.  Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota State District Court in Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006.  In November 2006, the court issued an order denying NSP-Minnesota’s motion.  On Nov. 28, 2006, pursuant to a motion by NSP-Minnesota, the court certified the issues raised in NSP-Minnesota’s original motion as important and doubtful.  This certification permits NSP-Minnesota to file an appeal, and it has done so.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court for the Southern District of Mississippi.  Although NSP-Minnesota is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on NSP-Minnesota.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence, and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.

AmeriPride Services vs. NSP — In August 2006, a complaint was served on NSP-Minnesota and suit was filed in the Hennepin County District Court in Minnesota, alleging that on or about Sept. 2, 2004, fires occurred on the premises of AmeriPride, a linen and apparel service facility in Minneapolis, and that the cause of the fire was NSP-Minnesota’s failure to properly repair a primary underground cable after two prior failures in the same cable.  AmeriPride claims damages slightly in excess of $2 million, and asserts claims of negligence, gross negligence, negligent inspection and maintenance, negligent design, negligent failure to install equipment to discontinue power, negligent continuation of power, and negligent misrepresentation.  NSP-Minnesota denies these allegations and will vigorously defend against them.

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

12. Nuclear Obligations

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent 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 permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes the DOE fuel disposal assessments of approximately $13 million in 2006, $12 million in 2005 and $13 million in 2004. In total, NSP-Minnesota had paid approximately $360 million to the DOE through Dec. 31, 2006. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

The Nuclear Waste Policy Act of 1982 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 an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools at both sites and a dry cask facility at Prairie Island. With the dry cask storage facility licensed by the NRC, approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its current license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the storage pool to continue operations until 2010. In 2005, NSP-Minnesota filed a certificate of need to allow interim storage of spent fuel at the Monticello nuclear plant to support license renewal and operation for an additional 20 years, and in October 2006, the MPUC issued its approval allowing additional interim spent fuel storage.  Minnesota Statutes provide that the MPUC decision becomes effective June 1, 2007, which allows the legislature the opportunity to review the MPUC action if desired.  All of the alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium-enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments for 15 years to 2007. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2006 was $4.9 million; future installments are subject to inflation adjustments under the DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $3.7 million at Dec. 31, 2006, is deferred as a regulatory asset.

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Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the period from cessation of operations through 2050, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the regulatory costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143.

Monticello began operation in 1971 with an original license to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are currently licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage.  On Sept. 28, 2006, the MPUC approved Xcel Energy’s request for a certificate of need to authorize construction and operation of a dry spent fuel storage facility at Monticello.  Minnesota statutes provide that the order is not effective until June 1, 2007.  The purpose of the stay is to give the state legislature the opportunity to review the MPUC action if lawmakers wish.  On Nov. 8, 2006, the NRC renewed the operating license of the Monticello nuclear plant for an additional 20 years to 2030.   Plant assessments and other work for the Prairie Island applications started in 2006.  The Prairie Island operating license extension for an additional 20 years of operation will be filed in 2008 with the NRC.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in March 2006, using 2005 cost data.  The MPUC approval decreasing 2006 decommissioning funding for Minnesota retail customers resulted from an extension of remaining life for the Monticello unit by 10 years (from 2010 to 2020).  Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2006, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Current authorized funding presumes that costs will escalate in the future at a rate of 3.61 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.4 percent, net of tax, for external funding. The net unrealized gain on nuclear decommissioning investments is deferred as a regulatory liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

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

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

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

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Decommissioning expenses recognized include the following components:

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

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

13. Regulatory Assets and Liabilities

NSP-Minnesota’s financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting.  If changes in the utility industry or the business of NSP-Minnesota no longer allow for the application of SFAS No. 71 under GAAP, NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in its statement of income.  The components of unamortized regulatory assets and liabilities on the balance sheets of NSP-Minnesota are:

		Remaining Amortization
(Thousands of Dollars)	See Note(s)	Period	2006		2005
Regulatory Assets:
AFDC recorded in plant (a)		Plant lives	$	106,088	$	96,296
Contract valuation adjustments (d)	8	Term of contract	68,188		53,425
Renewable resource costs		Two to Three years	49,902		46,889
Net asset retirement obligations (e)	11	Plant lives	36,945		155,814
Conservation programs (a)		Generally one year	31,448		29,670
Losses on reacquired debt	1	Term of related debt	25,944		29,081
Unrecovered natural gas costs (b)	1	One to two years	17,943		12,874
Private fuel storage		Five years	14,473		—
Minnesota renewable cost recovery			—		3,564
State commission accounting adjustments (a)		Plant lives	4,187		4,240
Nuclear decommissioning costs (c)		One year	3,700		8,317
Unrecovered electric production and MISO day 2 costs		To be determined in future rate proceedings	2,960		—
Rate case costs	1	Various	2,043		2,538
Environmental costs	11, 12	Various	2,237		3,001
Other		Various	6,291		4,491
Total regulatory assets			$	372,349	$	450,200
Regulatory Liabilities:
Plant removal costs	11		$	355,390	$	334,353
Pension and employee benefit obligations	6		185,425		397,261
Deferred income tax adjustments			48,644		57,430
Investment tax credit deferrals			32,902		35,993
Contract valuation adjustments (d)			16,420		6,631
Fuel costs, refunds and other			11,340		8,546
Interest on income tax refunds			5,208		5,981
MERP rider recoveries			3,242		—
Total regulatory liabilities			$	658,571	$	846,195

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

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

(c)These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to the DOE assessments to pay for the decommissioning of a federal uranium enrichment facility.  See Note 12 to the Consolidated Financial Statements.

(d)Includes the fair value of certain long-term contracts used to meet native energy requirements.

(e)Includes amounts recorded for future ecovery of asset retirement obligations, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

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14. Segments and Related Information

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

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

·NSP-Minnesota’s Regulated Natural Gas Utility transports, stores and distributes natural gas in portions of Minnesota and North Dakota.

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

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

·directly assigned wherever applicable;

·allocated based on cost causation allocators wherever applicable; or

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

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which are separately determined for each segment.

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
2006
Operating revenues from external customers	$	3,265,371	$	744,635	$	17,609		$	—		$	4,027,615
Intersegment revenues	496		8,929		—			(9,425		)	—
Total revenues	$	3,265,867	$	753,564	$	17,609		$	(9,425	)	$	4,027,615
Depreciation and amortization	$	393,560	$	31,566	$	385		$	—		$	425,511
Financing costs, mainly interest expense	134,347		15,539		1,040			(4		)	150,922
Income tax expense (benefit)	138,077		5,448		(15,919		)	—			127,606
Segment net income	$	242,815	$	9,674	$	19,821		$	—		$	272,310
2005
Operating revenues from external customers	$	3,010,957	$	821,922	$	20,705		$	—		$	3,853,584
Intersegment revenues	297		15,689		—			(15,986		)	—
Total revenues	$	3,011,254	$	837,611	$	20,705		$	(15,986	)	$	3,853,584
Depreciation and amortization	$	341,725	$	30,501	$	730		$	—		$	372,956
Financing costs, mainly interest expense	120,982		14,515		660			(22		)	136,135
Income tax expense (benefit)	116,517		7,717		(12,451		)	—			111,783
Segment net income	$	199,964	$	23,782	$	13,998		$	—		$	237,744
2004
Operating revenues from external customers	$	2,549,664	$	707,058	$	19,135		$	—		$	3,275,857
Intersegment revenues	821		4,658		—			(5,479		)	—
Total revenues	$	2,550,485	$	711,716	$	19,135		$	(5,479	)	$	3,275,857
Depreciation and amortization	$	307,048	$	28,787	$	909		$	—		$	336,744
Financing costs, mainly interest expense	113,405		14,349		875			(47		)	128,582
Income tax expense (benefit)	90,428		7,332		(3,147		)	—			94,613
Segment net income	$	206,726	$	23,131	$	417		$	—		$	230,274

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15. Related Party Transactions

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

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required FERC and state regulatory approvals.  See Note 2 for further discussion of this borrowing arrangement.

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

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

Following consummation of the sale transactions, NSP-Minnesota will be the sole remaining member of the NMC.  NSP-Minnesota is evaluating the situation.  One option under consideration is to transition the NMC to a wholly owned subsidiary of Xcel Energy.  To facilitate implementation of this option, Xcel Energy plans are progressing to restructure the NMC to support a two-site organization, as well as reabsorb the administrative functions within Xcel Energy by the end of 2007

In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating expenses and capital improvement costs incurred by NMC.  NSP-Minnesota paid the NMC $292.5 million in 2006, $257.1 million in 2005 and $314.7 million in 2004.

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

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

(Thousands of Dollars)	2006		2005		2004
Operating revenues:
Electric utility	$	322,733	$	305,202	$	220,165
Natural gas utility	350		386		303
Operating expenses:
Purchased power	61,342		60,801		55,222
Transmission expense	38,061		37,803		40,794
Other operations — paid to Xcel Energy Services Inc.	284,108		284,906		274,074
Interest expense	1,083		494		224
Interest income	4,497		1,326		335

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

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

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements. At Dec. 31, 2006 and 2005, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $30.3 million and $64.0 million, respectively.

16. Summarized Quarterly Financial Data (Unaudited)

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

	Quarter Ended
(Thousands of Dollars)	March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005
Revenue	$	943,471	$	854,565	$	976,935	$	1,078,613
Operating income	91,263		70,149		199,167		105,703
Net income	41,627		29,733		115,891		50,493

Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

During 2005 and 2006, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Minnesota on accounting principles or practices, financial statement disclosures or auditing scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the NSP-Minnesota’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

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

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Item 9B — Other Information

None.

PART III

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

Item 10 — Directors, Executive Officers, and Corporate Governance

Item 11 — Executive Compensation

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

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

Item 14 — Principal Accounting Fees and Services

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

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, 2006, 2005 and 2004.

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

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2006, 2005 and 2004.

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

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

3.Exhibits

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

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

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4.09*	June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
4.10*	April 1, 1997 (Exhibit 4.47 to Form 10-K (file no. 001-03034) for the year 1997).
4.11*	March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
4.12*	May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.13*	June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.14*	Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.15*	June 1, 2002 (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.16*	June 1, 2002 (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.17*	Aug. 1, 2002 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.18*	Aug. 1, 2003 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.19*	May 1, 2003 (Exhibit 4.73 to Form 10-K (file no. 000-03034) for the year ended Dec. 31, 2003).
4.20*	July 1, 2005 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated July 14, 2005).
4.21*	Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.22*	Supplemental Trust Indenture, dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.23*	Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.24*	Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.25*	Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.26*	Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between Northern States Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota, National Association, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
4.27*	Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.28*	Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.29*	Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988.
4.30*	Underwriting Agreement dated July 14, 2005 between NSP-Minnesota, Barclays Capital Inc. and J.P. Morgan Securities Inc., as representatives of the Underwriters named therein, relating to $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 1.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005).
4.31*	Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005).
4.32*	Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, dated May 18, 2006).
4.33*	$500,000,000 Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 99.01 to Form 8-K (file no. 000-31387) dated Dec. 14, 2006).
10.01*+	Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+	Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.03*+	Employment Agreement dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).

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

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10.34*	Xcel Energy Executive Annual Incentive Award Plan (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.35*	Xcel Energy Amended Employment Agreement, between Xcel Energy Inc. and Wayne H. Brunetti (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated June 29, 2005).
10.36*	Xcel Energy Supplemental Executive Retirement Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Dec. 13, 2005).
10.37+	Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2006
10.38+	Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy
10.39*	Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (kv) line. (Exhibit 5.06I to file no. 2-54310).
10.40*	Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06J to file no. 2-54310).
10.41*	Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06K to file no. 2-54310).
10.42*	Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.43*	Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.44*	Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
10.45*	Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 of NSP-Minnesota, file no. 000-31709).
10.46*	Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly
	known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.33 to NRG’s Registration on Form S-1, file no. 333-35096).
10.47*	Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co. (a Minnesota corporation). (Exhibit 10.34 to NRG’s Registration on Form S-1, file no. 333-35096).
10.48*	Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1, file no. 333-35096).
10.49*	Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.50*	500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no.001-31387) dated March 25, 2003).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

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SCHEDULE II

NSP-MINNESOTA
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2006, 2005 and 2004
(Thousands of Dollars)

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

(1)Recovery of amounts previously written off.

(2)Principally uncollectible accounts written off or transferred.

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SIGNATURES

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

	NORTHERN STATES POWER COMPANY
	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III Vice President and Chief Financial Officer (Principal Financial Officer)
February 26, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ RICHARD C. KELLY	/s/ DAVID M. SPARBY
Richard C. Kelly Chairman and Director (Principal Executive Officer)	David M. Sparby Executive Vice President, Acting President and   ChiefExecutive Officer (Principal Operating Officer)
/s/ GARY R. JOHNSON	/s/ BENJAMIN G.S. FOWKE III
Gary R. Johnson Vice President, General Counsel and Director	Benjamin G.S. Fowke III Vice President, Chief Financial Officer and Director (Principal Financial Officer)
/s/ PAUL J. BONAVIA	/s/ TERESA S. MADDEN
Paul J. Bonavia Vice President and Director	Teresa S. Madden Vice President and Controller (Principal Accounting Officer)
/s/ PATRICIA K. VINCENT
Patricia K. Vincent Vice President and Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES 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 its security holder.

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