NORTHERN STATES POWER CO - FORM 10-K

Attached files

file	filename
EX-12.1 - EXHIBIT 12.1 - NORTHERN STATES POWER CO	ex12_1.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO	ex99_01.htm
EX-23.01 - EXHIBIT 23.01 - NORTHERN STATES POWER CO	ex23_01.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO	ex32_01.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO	ex31_01.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO	ex31_02.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2010

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

Commission file number 001-31387

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)

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

Securities registered pursuant to Section 12(b) of the Act: None

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 in Rule 405 of the Securities Act. x Yes o No

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

Indicate by check mark whether the registrant (1) has filed 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. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

As of Feb. 28, 2011, 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 Definitive Proxy Statement for its 2011 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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

PART I		3
Item 1 — Business		3
	DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
	COMPANY OVERVIEW	7
	ELECTRIC UTILITY OPERATIONS	7
	Overview	7
	Public Utility Regulation	8
	Capacity and Demand	8
	Energy Sources and Related Transmission Initiatives	9
	Fuel Supply and Costs	12
	Fuel Sources	12
	Wholesale Commodity Marketing Operations	13
	Summary of Recent Federal Regulatory Developments	13
	Electric Operating Statistics	16
	NATURAL GAS UTILITY OPERATIONS	16
	Public Utility Regulation	16
	Capability and Demand	17
	Natural Gas Supply and Costs	17
	Natural Gas Operating Statistics	18
	ENVIRONMENTAL MATTERS	18
	EMPLOYEES	18
Item 1A — Risk Factors		19
Item 1B — Unresolved Staff Comments		26
Item 2 — Properties		27
Item 3 — Legal Proceedings		28
Item 4 — Reserved		28

PART II		28
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		28
Item 6 — Selected Financial Data		29
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 7A — Quantitative and Qualitative Disclosures About Market Risk		32
Item 8 — Financial Statements and Supplementary Data		34
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		83
Item 9A — Controls and Procedures		83
Item 9B — Other Information		83

PART III		84
Item 10 — Directors, Executive Officers and Corporate Governance		84
Item 11 — Executive Compensation		84
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		84
Item 13 — Certain Relationships and Related Transactions, and Director Independence		84
Item 14 — Principal Accountant Fees and Services		84

PART IV		84
Item 15 — Exhibits, Financial Statement Schedules		84

SIGNATURES		88

This Form 10-K is filed by 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 SEC. This report should be read in its entirety.

Index

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NMC	Nuclear Management Company, LLC a wholly owned subsidiary of NSP Nuclear Corporation
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado, a Colorado corporation
SPS	Southwestern Public Service Company, a New Mexico corporation
utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy	Xcel Energy Inc., a Minnesota corporation

Federal and State Regulatory Agencies
ASLB	Atomic Safety and Licensing Board
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; hydroelectric generation licensing; and accounting requirements for utility holding companies, service companies, and public utilities.
IRS	Internal Revenue Service
MOAG	Minnesota Office of Attorney General
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
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.
NERC	North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the FERC and government authorities in Canada, to develop and enforce reliability standards.
NRC	Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
OES	Office of Energy Security, Minnesota Department of Commerce.
PSCW	Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.
SDPUC	South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.
SEC	Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program. Includes a comprehensive list of programs that benefits customers who conserve energy or use electricity at off-peak times of day.
EIR	Environmental Improvement Rider. Recovers costs of improvements made to two Minnesota plants under the MERP program.
FCA	Fuel clause adjustment. A clause included in electric rate schedules that provides for monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.
GAP	Gas Affordability Program
MCR	Mercury Cost Recovery Rider
PGA	Purchased gas adjustment. A clause included in NSP-Minnesota’s retail gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent period.

Index

RDF	Renewable development fund. Supports the development of renewable energy projects.
RES	Renewable energy standard
SEP	State Energy Policy
TCR	Transmission cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities not included in the determination of NSP-Minnesota’s electric rates in retail electric rates in Minnesota. The TCR is revised annually as new transmission investments and costs are incurred.

Other Terms and Abbreviations
ACRS	Advisory Committee for Reactor Safety
AFUDC	Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
APBO	Accumulated Postretirement Benefit Obligation
ARC	Aggregator of Retail Customers
ARO	Asset retirement obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC	FASB Accounting Standards Codification
BART	Best Available Retrofit Technology
BRIGO	Buffalo Ridge Incremental Generation Outlet
BTA	Best Technology Available
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CapX2020	An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
CATR	Clean Air Transport Rule
CIPS	Critical Infrastructure Protection Standards
CO2	Carbon dioxide
Codification	FASB Accounting Standards Codification
CON	Certificate of need
CPCN	Certificate of Public Convenience and Necessity
CWA	Clean Water Act
CWIP	Construction work in progress
decommissioning	The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	· An underlying and a notional amount or payment provision or both;
	· Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and
	· Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.

Index

distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTRs	Financial Transmission Rights. Used to hedge the costs associated with transmission congestion.
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in MW (capacity) or MW hours (energy).
GHG	Greenhouse gas
JOA	Joint operating agreement among Xcel Energy’s utility subsidiaries
LIBOR	London Interbank Offered Rate
LLW	Low-level radioactive waste
LNG	Liquefied natural gas. Natural gas that has been converted to a liquid.
MACT	Maximum Achievable Control Technology
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MERP	Metropolitan Emissions Reduction Project.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
MRO	Midwest Reliability Organization
MVP	Multi-Value Project
native load	The customer demand of retail and wholesale customers that a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas	A naturally occurring mixture of gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
NEI	Nuclear Energy Institute
NOPR	Notice of proposed rulemaking
NOx	Nitrogen oxide
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PFS	Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PJM	PJM Interconnection, LLC
PRP	Potentially responsible party
rate base	The investor-owned plant facilities for generation, transmission, and distribution and other assets used in supplying utility service to the consumer.
RECB	Regional Expansion Criteria Benefits
RFP	Request for proposal
ROE	Return on equity
ROFR	Right of first refusal
RPS	Renewable Portfolio Standard. A regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.

Index

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.
SCR	Selective catalytic reduction
SIP	State implementation plan
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services
unbilled revenues	Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying	A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission	An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
Measurements
Btu	British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
Bcf	Billion cubic feet
KV	Kilovolts (one KV equals on the thousand volts)
KW	Kilowatts (one KW equals one thousand watts)
KWh	Kilowatt hours
MMBtu	One million Btus
MW	Megawatts (one MW equals one thousand KW)
Volt	The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts.
Watt	A measure of power production or usage.

Index

COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged primarily 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 6 percent of its total sales in 2010. 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 natural gas utility service to approximately 0.5 million customers. Approximately 89 percent of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2010. Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

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 Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Company, which holds real estate; and NSP Nuclear Corporation, which owns NMC.

NSP-Minnesota conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. Comparative segment revenues, income from continuing operations and related financial information are set forth in Note 15 to the accompanying consolidated financial statements.

NSP-Minnesota focuses on growing through investments in electric and natural gas rate base to 1) meet growing customer demands, 2) comply with environmental and renewable energy initiatives and 3) maintain or increase reliability and quality of service to customers. NSP-Minnesota files periodic rate cases, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. Environmental leadership is a strategic priority for NSP-Minnesota. Our environmental leadership strategy is designed to meet customer and policy maker expectations while creating shareholder value.

ELECTRIC UTILITY OPERATIONS

Overview

Environmental Regulations, Climate Change and Clean Energy — Electric utilities are subject to a significant array of environmental regulations. Further, there are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.

While environmental regulations, climate change and clean energy continue to evolve, NSP-Minnesota has undertaken a number of initiatives to meet current and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Although the impact of climate change policy on NSP-Minnesota will depend on the specifics of state and federal policies, legislation and regulation, we believe that, based on prior state commission practice, NSP-Minnesota would be granted the authority to recover the cost of these initiatives through rates.

Utility Competition — The FERC has continued its efforts to promote more competitive wholesale markets through open-access transmission and other means. As a consequence, NSP-Minnesota can purchase generation resources from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ to serve their native load.

Transmission — In June 2010, the FERC issued a NOPR that would eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory (referred to as a ROFR). The NOPR is pending FERC action. Irrespective of the NOPR, the utility subsidiaries are pursuing several new transmission facility projects.

Alternative Energy Options — NSP-Minnesota’s 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 or 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.

Index

Public Utility Regulation

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 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 that will be located within the state.

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 generating and transmission facilities, and the siting and routing of 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, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce. NSP-Minnesota received authorization from the FERC to make wholesale electric sales at market-based prices (see Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules discussion) and is a transmission-owner member of the MISO RTO.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

·	CIP — The CIP recovers the cost of programs that help customers save energy. CIP includes a comprehensive list of programs that benefit all customers including Saver’s Switch®, energy efficiency rebates and energy audits.

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

·	GAP — The GAP is a surcharge billed to all non-interruptible customers to recover the costs of offering a low-income customer co-pay program designed to reduce natural gas service disconnections.

·	MCR — The MCR recovers costs related to reducing Mercury emissions at two NSP-Minnesota fossil fuel power plants.

·	RDF — The RDF allocates money collected from retail customers to support the development of emerging renewable energy projects research and development of renewable energy technologies.

·	RES — The RES is a rider that recovers the costs of new renewable generation.

·	SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature.

·	TCR — The TCR recovers costs associated with new investments in the electric transmission system.

NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments 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 approved by the regulators in each jurisdiction.

The FCAs 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. In general, capacity costs are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or through rate cases.

Minnesota state law requires electric utilities to invest 1.5 percent of their state revenues in CIP, except NSP-Minnesota, which is required by law to invest 2 percent of state revenues. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

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 2011, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2008		2009		2010		2011 Forecast
NSP System		8,697		8,615		9,131		9,357

The peak demand for the NSP System typically occurs in the summer. The 2010 uninterrupted system peak demand for the NSP System occurred on Aug. 9, 2010.

Index

Energy Sources and Related Transmission Initiatives

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

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and independent power producers. 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 and a charge for the associated energy actually purchased.

NSP-Minnesota also makes short-term purchases to comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements.

Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO and regional transmission service providers to deliver power and energy to the NSP System for native load customers, which are retail and wholesale load obligations with terms of more than one year.

2010 NSP System Resource Decisions and Plan — In May 2010, NSP-Minnesota signed new power purchase and exchange agreements with Manitoba Hydro that will extend purchases through 2025. The existing agreements provided for the purchase of 850 MW, which would have started to expire in April 2015. NSP-Minnesota filed for approval with the MPUC in June 2010.

NSP-Minnesota filed its 2011-2025 resource plan in August 2010. In addition to the extension of contracts with Manitoba Hydro and previously approved life extensions and capacity increases at NSP-Minnesota’s nuclear generating plants, the near term actions in the plan include continued expansion of demand side management programs up to 1.5 percent of sales annually, the acquisition of up to 250 MW of additional wind power to be in service by 2012 if priced competitively, and the replacement of the remaining 270 MW of coal fired generation at the Black Dog generating plant with a 680 MW combined-cycle unit by January 2016.

Through the Interchange Agreement, the Minnesota resource plan and decisions have a direct impact on the costs that are shared by NSP-Wisconsin.

Wind Generation — NSP-Minnesota invested approximately $500 million in wind generation through 2010 and expects to invest an additional $400 million in 2011. The 201 MW Nobles Wind Project in southwestern Minnesota began commercial operations in 2010 and the 150 MW Merricourt Wind Project in southeastern North Dakota is expected to reach commercial operation in 2011. The portion of the costs for the Nobles and Merricourt Wind Projects assigned to Minnesota retail electric customers are currently being collected through the RES rider. NSP-Minnesota has included the costs for the Nobles Wind Project in its current pending rate case in Minnesota and if approved, the costs will be recovered in base rates when final rates are implemented. The NDPSC granted advanced determinations of prudence for the Nobles and Merricourt Wind Projects and a CPCN for the Merricourt Wind Project. This process provides greater assurance that NSP-Minnesota can recover the North Dakota portion of prudently incurred expenses for these projects.

NSP-Minnesota Transmission CONs — In May 2009, the MPUC granted a CON to construct three 345 kilovolt KV electric transmission lines as part of the CapX2020 project. The project to build the three lines includes construction of approximately 700 miles of new facilities at a cost of approximately $1.9 billion. The portion of the project cost to be constructed by NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $1.0 billion. The remainder of the costs will be born by other utilities in the upper Midwest. These cost estimates will be revised after the regulatory process is completed. The MPUC also included a condition assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy. In May 2010, NSP-Minnesota and other CapX2020 utilities notified the MPUC that the in-service date for the Brookings, S.D. to Hampton, Minn. project is expected to be delayed to the second quarter of 2015, more than one year after the date provided in the MPUC CON decision. The MPUC ordered NSP-Minnesota to provide a report in January 2011 to update the status of the project. NSP-Minnesota filed the report, which described the numerous activities in progress to allow the project to be placed in service by second quarter 2015.

As part of the regulatory process for the CapX2020 345 KV projects, NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the SDPUC, a certificate of corridor compatibility application with the NDPSC and a CPCN application with the PSCW. Two filed route permit applications have completed the evidentiary hearing processes, and the MPUC issued route permits for the Monticello, Minn. to St. Cloud, Minn. project and five of the six segments of the Brookings, S.D. to Hampton, Minn. project. One segment of the Brookings, S.D. to Hampton, Minn. line was referred back to the ALJ to develop more information concerning the appropriate location to cross the Minnesota River. That process has been completed and the ALJ issued recommendations in December 2010. In February 2011, the MPUC approved an aerial crossing of the Minnesota River. The other two CapX2020 route applications are expected to be sent to an evidentiary hearing in 2011.

Index

Bemidji to Grand Rapids

In July 2009, the MPUC approved the CON application for a 230 KV CapX2020 transmission line between Bemidji, Minn. and Grand Rapids, Minn. Route permit hearings were concluded in May 2010, and a route permit was approved by the MPUC in November 2010. This line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million. Construction related activities began in January 2011 and are expected to be completed in 2012. The estimated project cost to NSP-Minnesota is approximately $26 million.

Hiawatha Transmission Project

In November 2010, NSP-Minnesota submitted a CON application to the MPUC for two 115 KV lines in Minneapolis, Minn. Hearings on the CON will be held mid-2011 with an expectation of an MPUC decision of the CON and route permit by the end of 2011.

Glencoe to Waconia

In November 2010, NSP-Minnesota submitted a CON to the MPUC for 115 KV transmission line upgrades to the Glencoe, Minn. to Waconia, Minn. 69 KV line. This was followed by a route permit application filed in December 2010. Hearings on both applications will be held in mid-2011 with an expectation of an MPUC decision regarding both applications by the end of 2011.

Regulatory Investigations

Sewer Conflict Mitigation Deferred Accounting — In response to a February 2010 natural gas-fueled house fire in St. Paul, Minn., NSP-Minnesota initiated a three-year plan to investigate its natural gas system for conflicts between sewer lines and its natural gas lines, and are estimating plan costs at approximately $3.5 million per year. In December 2010, the MPUC approved deferred accounting of plan expenditures for recovery consideration in a future natural gas rate case.

ARCs — In 2009, the FERC adopted rules requiring MISO and other RTOs to allow ARCs to offer demand response aggregation services to end-use customers in the states unless the relevant state regulatory agency prohibited the operation of ARCs. Under MISO’s proposed tariff revisions, ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota. MISO requested its tariff revisions be effective in June 2010; however the FERC has not issued an order on MISO’s ARC-related tariff revisions. In May 2010, the MPUC and SDPUC issued orders prohibiting, or temporarily prohibiting, the operation of ARCs. In August 2010, the NDPSC issued an order prohibiting the operation of ARCs. In January 2011, the MPUC voted to require written comments on additional issues in September 2011, but did not modify the prohibition on ARCs set forth in the May 2010 order. In January 2011, the MPUC asked public utilities to explore the potential of programs with ARCs that compliment existing CIP initiatives.

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

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units. See additional discussion regarding the nuclear generating plants at Note 13 to the consolidated financial statements.

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. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

LLW Disposal — Federal law places responsibility on each state for securing a site to be used for the disposal of LLW generated within its borders. LLW from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah. . If off-site LLW disposal facilities become unavailable, NSP-Minnesota has 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.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of 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 spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository over the objections of the Governor of Nevada. In 2008, the DOE submitted an application to construct a deep geologic repository at Yucca Mountain to the NRC.

Index

In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC to approve the withdrawal of the application. A number of parties have challenged the DOE’s authority to stop the project and withdraw the application. The utility industry, including Xcel Energy, is represented in the challenges by the NEI. In light of the DOE’s plan to stop the project and withdraw its application, Xcel Energy in a separate action has requested the Secretary of Energy to set the fee collection rate for the Nuclear Waste Fund to zero until a definitive program is in place. In April 2010, the NEI, on behalf of its members, including Xcel Energy, filed a lawsuit against the DOE in federal court, requesting that the fee be suspended. In parallel with the action to stop the Yucca Mountain project, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposing of used nuclear fuel. The final report containing recommendations from the Blue Ribbon Commission is expected in early 2012.

In June 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application. The NRC Commissioners have made a decision to review the ASLB’s decision and have received briefs and reply briefs from parties. A decision from the NRC Commissioners could come in the first quarter 2011.

To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel. NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. As of Dec. 31, 2010, there were 29 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant. Additional discussion of the legal proceedings against the DOE related to the nuclear waste disposal matter is disclosed in Item 3 — Legal Proceedings and Note 14.

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 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 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. In 2007, PFS and the Skull Valley Band filed a lawsuit challenging these actions. The lawsuit remains pending. A judicial appeal of the NRC licensing decision has been held in abeyance pending the outcome of the lawsuit challenging the Department of the Interior decisions. The existence of PFS as a licensed out-of-state storage option remains a credible alternative if PFS and the Skull Valley Band can prevail in the pending litigation and if the federal government fails to make progress with their obligation to take title and remove spent nuclear fuel from all domestic reactor sites.

Nuclear Plant Power Uprates and Life Extension

Monticello Life Extension — In 2006, the NRC renewed Monticello’s operating license 20 years or until 2030.

Prairie Island Life Extension — In 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively. The NRC staff is proceeding with the items necessary to process Prairie Island’s license renewal application and NSP-Minnesota anticipates receiving a final decision on the Prairie Island license renewal in the second quarter of 2011.

Monticello Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello facility. The MPUC approved the extended power uprate in 2008. The filing was placed on hold by the NRC staff to address concerns raised by the ACRS related to containment pressure associated with pump performance. The industry submitted a white paper and the NRC staff recommended that the matter be addressed through specific filings to demonstrate any potential risk and mitigation measures. In a letter to the NRC staff, the ACRS indicated that modifications to the plant should be evaluated and made where practical. NSP-Minnesota is working with the NRC to determine whether an additional supplement to its filing will be necessary to address the issues and expects to complete the license proceeding in 2011.

Prairie Island Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for NSP-Minnesota’s Prairie Island Units 1 and 2. The MPUC approved the extended power uprate in 2009. NSP-Minnesota cannot file for NRC approval of the extended power uprate until after the NRC renews the plants’ current operating licenses. A decision is expected in 2011. The extended power uprates are scheduled to be implemented during the 2014 and 2015 refueling outages.

Index

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.

													Weighted
	Coal*				Nuclear				Natural Gas				Average
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Fuel Cost
2010	$	1.89	51	%	$	0.83	42	%	$	6.29	7	%	$	1.73
2009		1.78	57			0.70	39			7.36	4			1.61
2008		1.73	58			0.56	39			10.09	3			1.55

_________________________________

* Includes refuse-derived fuel and wood

See additional discussion of fuel supply and costs under Item 1A — Risk Factors.

Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2010 and 2009 were approximately 39 and 43 days usage, respectively. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana. Estimated coal requirements at NSP-Minnesota’s and NSP-Wisconsin’s major coal-fired generating plants were approximately 9.9 and 10.2 million tons per year at Dec. 31, 2010 and 2009, respectively.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 85 percent of their coal requirements in 2011, 75 percent of their coal requirements in 2012 and 31 percent of their coal requirements in 2013. Any remaining requirements will be filled through a RFP process or through over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements through 2013. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Nuclear — 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 with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2012, approximately 66 percent of the requirements for 2013 through 2017, and approximately 38 percent of the requirements for 2018 through 2025. Contracts for additional uranium concentrate supplies are currently being negotiated that are expected to provide a portion of the remaining open requirements through 2025.

Current contracts for conversion services cover 100 percent of the requirements through 2011, approximately 78 percent of the requirements from 2012 through 2016, and approximately 30 percent of the requirements for 2017 through 2025. Contracts for additional conversion services are being negotiated to provide a portion of remaining open requirements for 2012 and beyond.

Current enrichment services contracts cover 100 percent of 2011 through 2016 requirements, and approximately 54 percent of the requirements for 2017 through 2025. Contracts for additional enrichment services are being negotiated to provide a portion of the remaining open requirements for 2017 and beyond.

Fabrication services for Monticello are covered through 2014. A contract for fuel fabrication services for Monticello for 2015 and beyond is currently being negotiated. Prairie Island’s fuel fabrication is 100 percent committed to 2015.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Some exposure to spot market price volatility will remain, due to index-based pricing structures contained in some of the supply contracts.

Index

Natural gas — The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel. The supply, transportation and storage contracts expire in various years from 2011 to 2028. All of the natural gas supply contracts have pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC approved transportation tariff rates. These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers. 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, 2010, NSP-Minnesota’s commitments related to supply contracts were $14 million and commitments related to transportation and storage contracts were approximately $499 million. The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Wholesale Commodity Marketing Operations

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota, and enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s utility activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 11 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Penalty Guidelines Issued — The Energy Act required the FERC to adopt new regulations to implement various aspects of the Energy Act. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC. The guidelines establish a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation. Penalties range between a minimal amount and $72.5 million based on an application of a multiplier. The guidelines indicate that the FERC can deviate from the guidelines in its discretion. The guidelines can apply to any investigation where the FERC staff has not begun settlement negotiations regarding an alleged violation.

While Xcel Energy cannot predict the ultimate impact new FERC regulations will have on its operations or financial results, Xcel Energy is taking actions that are intended to comply with and implement new FERC rules and regulations as they become effective.

NERC Electric Reliability Standards Compliance

Compliance Audits and Self Reports

NSP-Minnesota and NSP-Wisconsin share all NSP System generation and transmission costs by means of a FERC-approved tariff commonly referred to as the Interchange Agreement. In 2008, the NSP System filed a self-report with the MRO regional entity relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain CIPS. In 2009, the NSP System reached agreement with the MRO that would resolve all open audit findings and self reports by payment of a non-material penalty. In April 2010, the NSP System executed a definitive settlement agreement. The settlement agreement has been approved by the NERC and was filed for FERC approval in December 2010. In January 2011, the FERC issued accepting the NERC approval with no further action.

In March 2010, the MRO conducted a joint compliance spot check to evaluate compliance with the NERC CIPS. The regional entity issued a non-public final report in August 2010 alleging violations of certain CIPS requirements, including certain violations common to all Xcel Energy utility subsidiaries. Xcel Energy disputes the alleged violations and is working to resolve the issues. To what extent the regional entities or NERC may seek to impose penalties for violations of CIPS is unknown at this time.

Index

In November 2010, the NSP System filed a self-report with the MRO regarding potential violations of certain NERC CIPS. Additional self-reports of potential violations of CIPS were filed in January 2011. Based on the issues identified with CIPS compliance, the utility subsidiaries submitted a mitigation plan that provides for a comprehensive review of their CIPS compliance programs. Whether and to what extent that penalties may be assessed against NSP-Minnesota for the issues identified and self reported to date is unclear.

In February 2011, the NSP System will be subject to a comprehensive triennial audit by the MRO regarding compliance with various NERC mandatory reliability standards, including CIPS.

NERC Compliance Investigations

In September 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection as a result of a series of transmission line outages. In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada. The initial transmission line outages occurred on the NSP System. In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the September 2007 event. Because the event affected more than one region, the NERC took over the investigation. In January 2010, the NERC issued a preliminary non-public report alleging the NSP System violated certain NERC reliability standards. The report represents the preliminary conclusions of the NERC and is subject to additional procedures at NERC, and ultimately FERC review. In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO. The final outcome of the compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC. NSP-Minnesota is fully cooperating with the investigation. In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO. The final outcome of the compliance investigation, and whether and to what extent NERC may seek to impose penalties for standards violations, is unknown at this time.

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In October 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions. In December 2010, the NERC issued a revised advisory extending the period for affected entities to complete their initial assessment and corrective actions until 2013 and 2014, respectively. The advisory compliance cost for the NSP System is estimated at approximately $5.9 million. NSP-Minnesota will seek recovery through applicable rate-making mechanisms.

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

Proposed Rulemaking on Transmission Planning and Cost Allocation — In June 2010, the FERC issued a NOPR regarding transmission planning and cost allocation. The NOPR would (1) require that local and regional transmission planning processes address public policy requirements established by state or federal laws or regulations; (2) improve coordination between neighboring transmission planning regions of interregional facilities; (3) eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory, referred to ROFR; and (4) require cost allocation methods for transmission facilities to satisfy newly established cost allocation principles. The FERC will consider the written comments provided on the NOPR prior to adopting a final rule. The content of the final rule cannot be predicted at this time; however, limiting an incumbent utility’s preferential ROFR to build transmission in its service territory states may have a negative impact on longer-term growth opportunities for the Xcel Energy utility subsidiaries.

MISO Transmission Pricing — Certain new higher voltage transmission facilities determined by MISO to meet RECB eligibility criteria in the MISO tariff are subject to an allocation of 20 percent of the facility costs to all loads in the 15 state MISO region.

In July 2010, MISO and certain member transmission owners, including NSP-Minnesota and NSP-Wisconsin, filed proposed changes to the MISO tariff that would provide for regional cost allocation for 100 percent of the costs associated with transmission projects identified by MISO as MVPs. On Dec. 16, 2010, the FERC approved the tariff revisions, with conditions, to be effective July 16, 2010. The MVP tariff provisions are pending final FERC action. The MISO independent board of directors must approve MVP eligibility before the costs of a specific project are eligible for regional rate recovery under the MISO Tariff.

Index

The MISO regional cost allocation methods require other customers in MISO to contribute to cost recovery for certain new transmission facilities constructed by NSP-Minnesota and NSP-Wisconsin. MISO approved the eligibility of the CapX2020 Fargo, N.D. and La Crosse, Wis. transmission expansion projects for 20 percent regional allocation; and NSP-Minnesota anticipates the Brookings, S.D. CapX2020 project will be recommended for eligibility as an MVP, and thus 100 percent regional cost allocation, during 2011. The CapX2020 Bemidji, Minn. transmission expansion project is not eligible for regional cost allocation. However, NSP-Minnesota and NSP-Wisconsin also pay a share of the costs of projects constructed by other transmission-owning entities in the MISO region found to be eligible for regional cost allocation. The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation are expected to be material in future periods.

Market-Based Rate Rules — Each of the Xcel Energy utility subsidiaries was granted market-based rate authority. Under market-based rate rules, the NSP System was reauthorized to sell wholesale power at market-based rates in June 2009.

MISO vs. PJM Complaint Proceedings — In March 2010, MISO filed two complaints against PJM at the FERC alleging that PJM violated generation redispatch requirements under the joint operating agreement between the two RTOs, and alleging that incorrect modeling of certain generators by PJM resulted in underpayments by PJM of up to $135 million to generators in MISO (including NSP-Minnesota and NSP-Wisconsin) for redispatch provided from 2002 to 2009. MISO asked the FERC to direct PJM to pay the underpaid amount, plus interest. In April 2010, PJM filed a complaint against MISO, alleging that MISO dispatched generation in the MISO region improperly under the RTO joint operating agreement, and requested that the FERC order MISO to pay PJM up to $25 million. In January 2011, MISO and PJM filed a settlement agreement with the FERC that would provide for no payments between the RTOs for prior period errors, but establishes a process to validate and periodically update the operational modeling to prevent future similar errors. The settlement is pending FERC approval.

Revenue Sufficiency Guarantee (RSG) Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy.

In August 2010, the FERC issued two RSG-related orders, one in which, among other items, it affirmed its initial decision to not require refunds for MISO’s failure to include virtual supply offers in its RSG calculations. The second order rejected various provisions of MISO’s redesign proposal, which was intended to replace the current RSG methodology. In December 2010, MISO filed a revised RSG tariff reflecting the 2009 “indicative” tariff proposal and subsequent FERC orders, to be effective March 2011.

FERC Audit of Wholesale FCA — In October 2009, the FERC notified NSP-Minnesota and NSP-Wisconsin that the FERC audit division began an audit of compliance with the FERC’s accounting and reporting regulations related to the calculation of the NSP-Minnesota and NSP-Wisconsin wholesale FCA for the period commencing Jan. 1, 2008.

FERC Audit of Transmission Incentives Compliance — In December 2007, the FERC granted NSP-Minnesota and NSP-Wisconsin approval to recover a return on CWIP on their investments in the BRIGO, Chisago, Minn. to Apple River, Wis. and CapX2020 transmission projects. The incentives are recovered through MISO transmission rates. In December 2010, the FERC notified NSP-Minnesota and NSP-Wisconsin that the FERC audit division is beginning an audit of their compliance with the FERC’s rules and orders related to collection of wholesale transmission investment incentives commencing December 2007.

Index

Electric Operating Statistics

	Year Ended Dec. 31,
	2010			2009			2008

Electric sales (Millions of KWh)
Residential		10,414			9,887			10,099
Commercial and industrial		25,189			24,603			25,847
Public authorities and other		266			265			260
Total retail		35,869			34,755			36,206
Sales for resale		2,234			3,899			3,692
Total energy sold		38,103			38,654			39,898

Number of customers at end of period
Residential		1,240,509			1,231,752			1,227,889
Commercial and industrial		150,894			149,187			148,060
Public authorities and other		6,291			6,055			6,067
Total retail		1,397,694			1,386,994			1,382,016
Wholesale		13			16			31
Total customers		1,397,707			1,387,010			1,382,047

Electric revenues (Thousands of Dollars)
Residential	$	1,095,862		$	1,006,380		$	1,018,810
Commercial and industrial		1,868,753			1,739,992			1,853,451
Public authorities and other		33,329			31,981			31,837
Total retail		2,997,944			2,778,353			2,904,098
Wholesale		79,555			102,786			180,618
Interchange revenues from NSP-Wisconsin		416,076			389,023			390,143
Other electric revenues		131,140			137,111			109,250
Total electric revenues	$	3,624,715		$	3,407,273		$	3,584,109

KWh sales per retail customer		25,663			25,058			26,198
Revenue per retail customer	$	2,145		$	2,003		$	2,101
Residential revenue per KWh.		10.52	¢		10.18	¢		10.09	¢
Commercial and industrial revenue per KWh		7.42			7.07			7.17
Wholesale revenue per KWh		3.56			2.64			4.89

NATURAL GAS UTILITY OPERATIONS

The most significant developments in the natural gas operations of NSP-Minnesota are continued volatility in natural gas market prices, safety requirements for natural gas pipelines and the continued trend of declining use per customer by residential customers, as well as small commercial and industrial (C&I) customers, as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2010, average annual sales to the typical residential customer declined from 107 MMBtu per year to 86 MMBtu per year, and to a typical small C&I customer declined from 376 MMBtu to 342 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, high prices can encourage further efficiency efforts by customers.

Public Utility Regulation

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 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. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Minnesota is subject to the U.S. Department of Transportation, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline safety compliance.

Index

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 cost revenues 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 in the state of Minnesota. These costs were recovered from Minnesota customers through an annual cost-recovery mechanism for natural gas conservation and energy management program expenditures. In 2010, this law changed to an energy savings-based requirement, and the costs of conservation improvement programs will continue to be recoverable in Minnesota through a rate adjustment mechanism.

For a further discussion of rate and regulatory matters see Note 11 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 689,223 MMBtu for 2010, which occurred on Dec. 13, 2010.

NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 585,598 MMBtu per day. In addition, NSP-Minnesota contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 26 percent of winter natural gas requirements and 32 percent of peak day firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 31 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 2009-2010 and 2010-2011 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.

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:

2010	$	5.43
2009		5.78
2008		8.41

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 2011 through 2029.

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, 2010, NSP-Minnesota was committed to approximately $524 million in such obligations under these contracts.

Index

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 29 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2010			2009			2008

Natural gas deliveries (Thousands of MMBtu)
Residential		36,300			39,329			41,589
Commercial and industrial		38,609			40,408			42,640
Total retail		74,909			79,737			84,229
Transportation and other		9,455			6,784			6,772
Interdepartment deliveries		8,787			6,154			6,241
Total deliveries		93,151			92,675			97,242

Number of customers at end of period
Residential		440,680			437,517			434,987
Commercial and industrial		40,772			40,468			40,174
Total retail		481,452			477,985			475,161
Transportation and other		19			15			15
Total customers		481,471			478,000			475,176

Natural gas revenues (Thousands of Dollars)
Residential	$	319,418		$	347,348		$	467,751
Commercial and industrial		258,943			283,953			413,871
Total retail		578,361			631,301			881,622
Transportation and other		10,683			9,022			8,336
Total natural gas revenues	$	589,044		$	640,323		$	889,958

MMBtu sales per retail customer		155.59			166.82			177.26
Revenue per retail customer	$	1,201		$	1,321		$	1,855
Residential revenue per MMBtu		8.80	¢		8.83	¢		11.25	¢
Commercial and industrial revenue per MMBtu		6.71			7.03			9.71
Transportation and other revenue per MMBtu		1.13			1.33			1.23

ENVIRONMENTAL MATTERS

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. NSP-Minnesota 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 12 and 13 to the consolidated financial statements.

EMPLOYEES

The number of full-time NSP-Minnesota employees at Dec. 31, 2010 and 2009 was 3,689 and 3,763, respectively. Of these full-time employees, 2,279, or 62 percent and 2,341, or 62 percent, respectively, are covered under collective bargaining agreements. The collective bargaining agreements expired at the end of 2010 and as of Dec. 31, 2010, contract negotiations were in process. Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to NSP-Minnesota and are not considered in the above amounts.

Index

Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes NSP-Minnesota, is to understand, manage and, when possible, mitigate material risk; management is responsible for identifying and managing risks, while Xcel Energy’s Board of Directors oversees and holds management accountable. As described more fully below, NSP-Minnesota is faced with a number of different types of risk. We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2; risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services. Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and NSP-Minnesota’s senior management. Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

Our management identifies and analyzes risks to determine materiality and other attributes like timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economy and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. At the same time, the business planning process identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy’s and NSP-Minnesota’s strategy. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management. At a threshold level, we have developed a robust compliance program and promote a culture of compliance, which mitigates risk. Building on this culture of compliance, we manage and mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services. While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

Management also communicates with Xcel Energy’s Board and key stakeholders regarding risk. Management provides information to Xcel Energy’s Board in presentations and communications over the course of the year. Senior management presents an assessment of key risks to the Board annually. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s and NSP-Minnesota’s strategy. The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. The Xcel Energy Board has overall responsibility for risk oversight. As described above, the Board reviews the key risk assessment process presented by senior management. This key risk assessment analyzes the most likely areas of future risk to Xcel Energy. The Xcel Energy Board also reviews the performance and annual goals of each business area. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

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Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations 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 may be required to 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, 2010, these sites included:

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

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

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to regulation of mercury, NOx, SO2, CO2, particulates and coal ash. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

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To the extent climate change impacts a region’s economic health, it may also impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

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 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, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our costs incurred in a test year. Thus, the rates we are allowed to charge may or may not match our costs 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 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.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, 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 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. 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 & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology. Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy, such as the recent concerns regarding European sovereign debt. Capital market disruption events, and resulting broad financial market distress, such as the events surrounding the collapse in the U.S. sub-prime mortgage market, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning fund and master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

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We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. Retail credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

Credit risk also includes the risk that various 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.

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The recently enacted Dodd-Frank Wall Street Reform Act may require broad clearing of financial swap transactions through a central counterparty, which may lead to additional margin requirements that could impact our liquidity. Also, in October 2010, the FERC finalized its rulemaking addressing the credit policies of organized electric markets, such as MISO, which may lead to additional margin requirements that could impact our liquidity.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as PJM and MISO, in which any credit losses are socialized to all market participants.

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

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

We have defined benefit pension 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 economic conditions, actual stock market performance, changes in interest rates and 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 and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position, and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Legislation related to health care could also significantly change our benefit programs and costs.

Operational Risks

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

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 volatility. Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

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If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such disruption, if significant, 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. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.

We are subject to the risks of nuclear generation.

Our two nuclear stations, Prairie Island and Monticello, subject us 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 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 NRC safety requirements could necessitate substantial capital expenditures at our nuclear plants. In addition, the Institute for Nuclear Power Operations reviews our nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

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 our compliance costs and impact the results of operations of its facilities.

Our utility operations are subject to long-term planning risks.

On a periodic basis, or as needed, our utility operations file long-term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.

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

There are inherent in our natural gas transmission and distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which 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 natural gas transmission or distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks is greater.

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As we are a subsidiary of Xcel Energy, we may be negatively affected by events impacting the credit or liquidity of 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 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 of Dec. 31, 2010, Xcel Energy had approximately $9.3 billion of long-term debt and $0.5 billion of short-term debt and current maturities. Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for 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, 2010, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $155.7 million and $18.0 million of exposure. Xcel Energy also had additional guarantees of $32.5 million at Dec. 31, 2010 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund 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.

All of the members of 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 2010, 2009 and 2008 we paid $233.2 million, $232.7 million and $229.7 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 limited to some extent by our indenture for our first mortgage bonds.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change and emissions, with which compliance could be difficult and costly.

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress. Internationally, other nations have already agreed to regulate emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” by 2012. In addition, in 2009, the United States submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord. Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA. In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants in July 2011, with final standards to be issued in 2012.

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We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 12, Commitments and Contingent Liabilities, in the notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation or regulation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include, but are not limited to, rules associated with mercury, regional haze, ozone, ash management and cooling water intake systems. The costs of investment to comply with these rules could be substantial. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

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

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged economic recession and uncertainty of recovery may result in a sustained lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets. A sustained lower level of economic activity may also 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 capital, which are discussed in greater detail in the capital market risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.

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

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, including our nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

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. For example, wildfire events, particularly in the geographic areas we serve, may cause insurance for wildfire losses to become difficult or expensive to obtain.

A security breach of our information systems could impact the reliability of the our generation, transmission and distribution systems and also subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to system operating information and information regarding our customers and employees. We are unable to quantify the potential impact of such an event, however, such an event could result in significant costs and penalties, as well as legal costs.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because our generation, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events, potentially through the execution of our business continuity plans, will in part determine the financial impact of certain events on our financial condition and results. It’s difficult to predict the magnitude of such events and associated impacts.

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, higher fuel costs could reduce customer demand and/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 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 and natural gas utility 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.

Item 1B — Unresolved 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:

NSP-Minnesota			Summer 2010
			Net Dependable
Station, Location and Unit	Fuel	Installed	Capability (MW)
Steam:
A.S. King-Bayport, Minn	Coal	1968	511
Sherco-Becker, Minn.
Unit 1	Coal	1976	680
Unit 2	Coal	1977	682
Unit 3	Coal	1987	507	(a)
Monticello-Monticello, Minn.	Nuclear	1971	554
Prairie Island-Welch, Minn.
Unit 1	Nuclear	1973	521
Unit 2	Nuclear	1974	519
Black Dog-Burnsville, Minn., 2 Units	Coal/Natural Gas	1955-1960	241
Various locations, 4 Units	Wood/RDF	Various	36	(c)
Combustion Turbine:
Angus Anson-Sioux Falls, S.D., 3 Units	Natural Gas	1994-2005	338
Black Dog-Burnsville, Minn., 2 Units	Natural Gas	1987-2002	243
Blue Lake-Shakopee, Minn., 6 Units	Natural Gas	1974-2005	467
High Bridge-St. Paul, Minn., 3 Units	Natural Gas	2008	488
Inver Hills-Inver Grove Heights, Minn., 6 Units	Natural Gas	1972	282
Riverside-Minneapolis, Minn., 3 Units	Natural Gas	2009	473
Various locations, 18 Units	Natural Gas	Various	107
Wind:
Grand Meadow-Mower County, Minn.	Wind	2008	101	(b)
Nobles-Nobles County, Minn.	Wind	2010	201	(b)
		Total	6,951

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

(b)	This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above. Therefore, the on-demand net dependable capacity is zero.

(c)	RDF is refuse-derived fuel, made from municipal solid waste.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2010:

Conductor Miles
500 KV			2,917
345 KV			6,387
230 KV			1,801
161 KV			385
115 KV			7,362
Less than 115 KV			82,692

NSP-Minnesota had 369 electric utility transmission and distribution substations at Dec. 31, 2010.

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Natural gas utility mains at Dec. 31, 2010:

Miles
Transmission			135
Distribution			9,586

Item 3 — Legal Proceedings

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

Legal Contingencies

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the DOE failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota. At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue. It is uncertain when the Court will issue a decision. Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved. Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have an effect on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U.S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract. This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel. Per the court’s scheduling order, NSP-Minnesota believes that it has suffered damages in excess of $250 million. The DOE claims NSP-Minnesota is entitled to at most approximately $55 million. Trial is expected to take place in 2011.

Additional Information

For a discussion of legal claims and environmental proceedings, see Note 12 to the consolidated financial statements. For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation and Summary of Recent Federal Regulatory Developments and Note 11 to the consolidated financial statements.

Item 4 — Reserved

PART II

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

NSP-Minnesota is a 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 $1.1 billion in additional cash dividends on common stock at Dec. 31, 2009, or $1.1 billion at Dec. 31, 2010.

In addition, NSP-Minnesota had dividend restrictions imposed by its credit facility, FERC rules and state regulatory commissions.

NSP-Minnesota’s credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent. NSP-Minnesota was in compliance as its equity-to-total capitalization ratio was 51 percent and 52 percent at Dec. 31, 2010 and 2009, respectively.

·	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.

State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy by requiring an equity-to-total capitalization ratio between 45.99 percent and 56.21 percent. NSP-Minnesota was in compliance as described above. Total capitalization for NSP-Minnesota cannot exceed $7.5 billion.

Index

The dividends declared during 2010 and 2009 were as follows:

(Thousands of Dollars)	2010		2009
First quarter	$	57,675	$	57,256
Second quarter		58,479		58,575
Third quarter		58,655		58,463
Fourth quarter		58,372		58,415

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).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Minnesota’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying consolidated financial statements and notes to the consolidated financial statements.

Forward-Looking 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. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. 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 and its subsidiaries 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 and its subsidiaries; 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 or impose environmental compliance conditions; 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; environmental laws and regulations; actions of accounting regulatory bodies; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2010 and Exhibit 99.01 to NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2010.

Results of Operations

NSP-Minnesota’s net income was approximately $274.2 million for 2010, compared with approximately $293.8 million for 2009. The decrease is primarily due to higher O&M expenses, property taxes and depreciation expense partially offset by the positive impact of warmer temperatures, higher earned incentives on energy efficiency and conservation programs and modest normalized sales growth.

Index

Electric Revenues and Margins

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:

(Millions of Dollars)	2010			2009
Electric revenues	$	3,625		$	3,407
Electric fuel and purchased power		(1,536	)		(1,412	)
Electric margin	$	2,089		$	1,995

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

Electric Revenues

(Millions of Dollars)	2010 vs. 2009
Fuel and purchased power cost recovery	$	78
Conservation revenue and incentive (partially offset by expenses)		47
Estimated impact of weather		40
Non-fuel riders		31
Interchange agreement billing with NSP-Wisconsin		27
Retail rate increase (South Dakota)		10
Retail sales increase (excluding weather impact)		6
Firm wholesale		(21	)
Total increase in electric revenues	$	218

Electric Margin

(Millions of Dollars)	2010 vs. 2009
Conservation revenue and incentive (partially offset by expenses)	$	47
Estimated impact of weather		40
Non-fuel riders		31
Retail rate increase (South Dakota)		10
Interchange agreement billing with NSP-Wisconsin		7
Retail sales increase (excluding impact of weather)		6
Deferred fuel adjustments		(20	)
Firm wholesale		(11	)
Timing of fuel recovery		(10	)
Other, net		(6	)
Total increase in electric margin	$	94

Natural Gas Revenues and Margins

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. The following table details natural gas revenues and margin:

(Millions of Dollars)	2010			2009
Natural gas revenues	$	589		$	640
Cost of natural gas sold and transported		(400	)		(464	)
Natural gas margin	$	189		$	176

Index

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

Natural Gas Revenues

(Millions of Dollars)	2010 vs. 2009
Purchased natural gas adjustment clause recovery	$	(58	)
Estimated impact of weather		(6	)
Conservation revenue and incentive (partially offset by expenses)		11
Rate increase (Minnesota)		6
Other, net		(4	)
Total decrease in natural gas revenues	$	(51	)

Natural Gas Margin

(Millions of Dollars)	2010 vs. 2009
Conservation revenue and incentive (partially offset by expenses)	$	11
Rate increase (Minnesota)		6
Estimated impact of weather		(6	)
Other, net		2
Total increase in natural gas margin	$	13

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses for 2010 increased $69.4 million, or 7.2 percent, compared to 2009. The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2010 vs. 2009
Higher nuclear plant operation costs	$	20
Higher plant generation costs		14
Higher nuclear outage costs, net of deferral		10
Higher labor costs		10
Higher employee benefit costs		9
Other, net		6
Total increase in O&M expenses	$	69

Higher nuclear plant operation costs are mainly due to increase labor and security expenses.

Higher plant generation costs are primarily attributable to the timing of planned maintenance and overhaul work.

Higher nuclear outage costs are due to the timing and higher cost of nuclear refueling outages.

Higher labor costs are primarily due to higher overtime for storm restoration work and a shift in labor resources from capital to O&M projects.

Higher employee benefit costs for the year are primarily due to increased pension costs.

Conservation Program Expenses — Conservation program expenses increased $27.1 million, or 45.7 percent, for 2010, compared with 2009. The higher expense was primarily attributable to the continued expansion of programs and regulatory commitments. NSP-Minnesota has established conservation incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system. This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers. NSP-Minnesota generally recovers conservation program expenses concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $11.8 million, or 3.0 percent, for 2010, compared with 2009. The change in depreciation expense from 2009 to 2010 is primarily due to normal system expansion.

Index

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased by approximately $15.7 million, or 10.7 percent, for 2010, compared with 2009. The increase was due to increased property taxes.

AFUDC — AFUDC increased by approximately $10.9 million, or 23.3 percent, for 2010 compared with 2009. NSP-Minnesota’s overall increase was primarily due to a slightly higher AFUDC equity rate.

Interest Charges — Interest charges increased by approximately $6.6 million, or 3.5 percent, for 2010, compared with 2009. The increase was due to new debt issuances.

Income Taxes — Income tax expense increased by $6.1 million for 2010, compared with 2009. The increase in income tax expense was primarily due to increased state unitary tax expense and a write-off of tax benefit previously recorded for Medicare Part D subsidies in 2010, partially offset by a decrease in pretax income in 2010 and additional tax expense related to prior year true-ups in 2009. The effective tax rate was 39.8 percent for 2010, compared with 37.3 percent for 2009. The higher effective tax rate for 2010 was primarily due to increased state unitary tax expense and the write-off of tax benefit related to Medicare Part D subsidies in 2010, partially offset by increased plant-related deductions in 2010 and additional tax expense related to prior year true-ups in 2009.

The effective tax rates for 2010 and 2009 differ from their statutory federal income tax rates, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant-related regulatory differences. See Note 6 to the consolidated financial statements.

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 or gain 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. Market risks associated with derivatives are discussed in further detail in Note 9 to the consolidated financial statements.

NSP-Minnesota is exposed to the impact of changes in price for energy and energy related products, which is partially mitigated by NSP-Minnesota’s use of commodity derivatives. Though no material non-performance risk currently exists with the counterparties to NSP-Minnesota’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the debt and equity securities in the nuclear decommissioning fund and master pension trust, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.

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 long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in 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 to the extent such exposure exists.

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, energy and energy-related instruments. NSP Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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

(Thousands of Dollars)	2010			2009
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	8,976		$	3,615
Contracts realized or settled during the period		(8,261	)		(11,681	)
Commodity trading contract additions and changes during period		17,716			17,042
Fair value of commodity trading net contract assets outstanding at Dec. 3	$	18,431		$	8,976

Index

At Dec. 31, 2010, the fair values by source for the commodity trading net asset balance were as follows:

Futures / Forwards

Maturity

Total Futures/

Source of

Less Than

Maturity

Greater Than

Forwards

(Thousands of Dollars)

Fair Value

1 Year

1 to 3 Years

4 to 5 Years

5 Years

Fair Value

NSP-Minnesota

5,914

11,523

976

18,413

Options

Maturity

Source of

Less Than

Maturity

Greater Than

Total Options

(Thousands of Dollars)

Fair Value

1 Year

1 to 3 Years

4 to 5 Years

5 Years

Fair Value

NSP-Minnesota

1 — Prices actively quoted or based on actively quoted prices.

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

Normal purchases and sales transactions, as defined by the accounting guidance for derivatives and hedging, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.

At Dec. 31, 2010, a 10 percent increase in market prices over the next 12 months for commodity trading contracts would increase pretax income from continuing operations by approximately $0.1 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.1 million.

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 Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:

	Year Ended
(Millions of Dollars)	Dec. 31			VaR Limit			Average			High			Low
2010		$	0.15		$	3.00		$	0.22		$	0.64		$	0.03
2009			0.50			5.00			0.44			2.02			0.06

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.

At Dec. 31, 2010, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would have no impact on pretax interest expense. See Note 9 to the consolidated financial statements for a discussion of NSP-Minnesota’s interest rate derivatives.

NSP-Minnesota also maintains a nuclear decommissioning fund as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At Dec. 31, 2010, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other funds. 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 — NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their 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.

Index

At Dec. 31, 2010, a 10 percent increase in prices would have resulted in a decrease in credit exposure of $4.2 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $10.9 million.

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

Fair Value Measurements

NSP-Minnesota follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and generally requires that the most observable inputs available be used for fair value measurements. Note 9 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2010. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues when necessary. Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2010.

Commodity derivative assets and liabilities assigned to Level 3 consist primarily of FTRs, as well as forwards and options that are either long-term in nature or related to commodities and delivery points with limited observability. Level 3 commodity derivative liabilities represent approximately 5 percent of total liabilities measured at fair value at Dec. 31, 2010. Level 3 commodity derivative assets represent an immaterial percent of total assets measured at fair value at Dec. 31, 2010.

Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities include $3.6 million and $1.3 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2010.

Determining the fair value of certain commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were no Level 3 commodity forwards or options held at Dec. 31, 2010.

Nuclear Decommissioning Fund — Nuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities. To the extent appropriate, observable market inputs are utilized to estimate the fair value of these securities; however, less observable and subjective inputs are often significant to these valuations, including risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated prepayments of principal. Therefore, estimated fair values for all asset-backed and mortgage-backed securities totaling $105.8 million in the nuclear decommissioning fund at Dec. 31, 2010 (approximately 7.6 percent of total assets measured at fair value), are assigned to Level 3. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a regulatory asset for nuclear decommissioning.

Item 8 — Financial Statements and Supplementary Data

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

See Note 17 to the consolidated financial statements for summarized quarterly financial data.

Index

Management Report on Internal Controls Over Financial Reporting

The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Minnesota’s internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.

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

NSP-Minnesota management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2010, the company’s internal control over financial reporting is effective based on those criteria.

/S/ JUDY M. POFERL		/S/ DAVID M. SPARBY
Judy M. Poferl		David M. Sparby
President and Chief Executive Officer		Vice President and Chief Financial Officer
Feb. 28, 2011		Feb. 28, 2011

Index

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Northern States Power Company, a Minnesota corporation

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company, a Minnesota corporation, and subsidiaries (the “Company”) as of December 31, 2010 and 2009, 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, 2010. 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, a Minnesota corporation, and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

Feb. 28, 2011

Index

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31,
	2010			2009			2008
Operating revenues
Electric	$	3,624,715		$	3,407,273		$	3,584,109
Natural gas		589,044			640,323			889,958
Other		20,557			19,093			19,569
Total operating revenues		4,234,316			4,066,689			4,493,636

Operating expenses
Electric fuel and purchased power		1,536,076			1,411,877			1,680,795
Cost of natural gas sold and transported		399,524			464,043			701,687
Cost of sales — other		12,405			11,076			10,034
Other operating and maintenance expenses		1,037,752			968,370			877,497
Conservation program expenses		86,298			59,244			65,876
Depreciation and amortization		401,136			389,367			412,362
Taxes (other than income taxes)		162,901			147,193			138,184
Total operating expenses		3,636,092			3,451,170			3,886,435

Operating income		598,224			615,519			607,201

Other income, net		1,151			1,572			10,895
Allowance for funds used during construction — equity		38,341			28,848			26,510

Interest charges and financing costs
Interest charges — includes other financing costs of $5,645, $5,778, and $5,834, respectively		201,431			194,808			198,369
Allowance for funds used during construction — debt		(19,131	)		(17,760	)		(17,140	)
Total interest charges and financing costs		182,300			177,048			181,229


Income before income taxes		455,416			468,891			463,377
Income taxes		181,191			175,121			178,236
Net income	$	274,225		$	293,770		$	285,141

See Notes to Consolidated Financial Statements

Index

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31,
	2010			2009			2008
Operating activities
Net income	$	274,225		$	293,770		$	285,141
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		401,602			394,712			407,343
Nuclear fuel amortization		105,369			80,104			64,203
Deferred income taxes		251,747			177,347			140,701
Amortization of investment tax credits		(2,697	)		(3,120	)		(3,503	)
Allowance for equity funds used during construction		(38,341	)		(28,848	)		(26,510	)
Provision for bad debts		15,213			19,408			25,506
Net realized and unrealized hedging and derivative transactions		(8,784	)		(4,960	)		(4,484	)
Changes in operating assets and liabilities
Accounts receivable		(24,216	)		74,818			21,928
Accrued unbilled revenues		(20,055	)		19,113			(22,050	)
Inventories.		(24,254	)		89,984			(75,265	)
Other current assets		(858	)		(13,589	)		11,394
Accounts payable		(70,715	)		39,229			14,557
Net regulatory assets and liabilities		18,575			(70,879	)		(12,876	)
Other current liabilities		39,899			19,066			(13,348	)
Change in other noncurrent assets		459			44			15,781
Change in other noncurrent liabilities		(42,873	)		(25,122	)		(37,139	)
Net cash provided by operating activities		874,296			1,061,077			791,379

Investing activities
Utility capital/construction expenditures		(1,209,402	)		(844,556	)		(1,015,827	)
Allowance for equity funds used during construction		38,341			28,848			26,510
Purchase of investments in external decommissioning fund		(3,781,438	)		(1,644,278	)		(957,752	)
Proceeds from sale of investments in external decommissioning fund		3,786,373			1,664,957			914,514
Investments in utility money pool arrangement		(246,000	)		(132,500	)		(943,400	)
Repayments from utility money pool arrangement		253,000			125,500			943,400
Advances to affiliate		(302,300	)		(62,500	)		(337,600	)
Advances from affiliate		280,800			47,000			396,200
Other investments		509			(6,415	)		10,501
Net cash used in investing activities		(1,180,117	)		(823,944	)		(963,454	)

Financing activities
Repayment of short-term borrowings, net		-			(65,000	)		(276,500	)
Borrowings under utility money pool arrangement		711,000			601,700			433,300
Repayments under utility money pool arrangement		(711,000	)		(665,200	)		(464,900	)
Proceeds from issuance of long-term debt		493,390			295,340			493,751
Repayment of long-term debt, including reacquisition premiums		(175,034	)		(250,041	)		(10	)
Capital contributions from parent		212,794			112,736			203,863
Dividends paid to parent		(233,224	)		(232,708	)		(229,712	)
Net cash provided by (used in) financing activities		297,926			(203,173	)		159,792

Net (decrease) increase in cash and cash equivalents		(7,895	)		33,960			(12,283	)
Cash and cash equivalents at beginning of period		46,303			12,343			24,626
Cash and cash equivalents at end of period	$	38,408		$	46,303		$	12,343

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(172,463	)	$	(178,017	)	$	(170,168	)
Cash received (paid) for income taxes, net		81,836			24,719			(27,292	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	59,836		$	34,172		$	24,109

See Notes to Consolidated Financial Statements

Index

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31,
Assets	2010		2009
Current assets
Cash and cash equivalents	$	38,408	$	46,303
Notes receivable from affiliates		37,000		15,500
Investments in utility money pool arrangement		-		7,000
Accounts receivable, net		313,485		300,103
Accounts receivable from affiliates		26,866		31,245
Accrued unbilled revenues		249,393		229,338
Inventories		280,173		255,919
Regulatory assets		164,943		200,266
Derivative instruments		39,892		59,482
Prepayments and other		39,229		38,095
Total current assets		1,189,389		1,183,251

Property, plant and equipment, net		7,822,220		6,958,656

Other assets
Nuclear decommissioning fund and other investments		1,366,069		1,264,687
Regulatory assets		671,391		627,825
Derivative instruments		101,258		117,216
Other		31,333		23,581
Total other assets		2,170,051		2,033,309
Total assets	$	11,181,660	$	10,175,216

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	19	$	175,037
Accounts payable		384,455		407,500
Accounts payable to affiliates		61,753		83,759
Taxes accrued		140,020		125,650
Accrued interest		66,641		62,780
Dividends payable to parent		58,372		58,415
Derivative instruments		27,311		24,661
Regulatory liabilities		42,122		33,858
Other		103,525		73,453
Total current liabilities		884,218		1,045,113

Deferred credits and other liabilities
Deferred income taxes		1,449,082		1,176,673
Deferred investment tax credits		34,437		37,134
Asset retirement obligations		875,361		797,476
Regulatory liabilities		462,574		435,911
Pension and employee benefit obligations		351,130		310,066
Derivative instruments		197,771		209,528
Other		93,025		83,965
Total deferred credits and other liabilities		3,463,380		3,050,753

Commitments and contingent liabilities
Capitalization
Long-term debt		3,337,893		2,838,141
Common stock – authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares		10		10
Additional paid-in capital		2,241,387		2,028,593
Retained earnings		1,251,938		1,210,894
Accumulated other comprehensive income		2,834		1,712
Total common stockholder's equity		3,496,169		3,241,209
Total liabilities and equity	$	11,181,660	$	10,175,216

See Notes to Consolidated Financial Statements

Index

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(amounts in thousands of dollars, except share data)

	Common Stock									Accumulated			Total
					Additional					Other			Common
			Par		Paid In		Retained			Comprehensive			Stockholder's
	Shares		Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2007		1,000,000	$	10	$	1,711,994	$	1,097,357		$	6,268		$	2,815,629
Adoption of new accounting guidance for endorsement split-dollar life insurance, net of tax of $(401)								(633	)					(633	)
Net income								285,141						285,141
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $228											331			331
Net derivative instrument fair value changes during the period, net of tax of $(3,901)											(5,651	)		(5,651	)
Unrealized loss - marketable securities, net of tax of $(513)											(743	)		(743	)
Comprehensive income for the period														279,078
Common dividends declared to parent								(232,032	)					(232,032	)
Contribution of capital by parent						203,863								203,863
Balance at Dec. 31, 2008		1,000,000	$	10	$	1,915,857	$	1,149,833		$	205		$	3,065,905
Net income								293,770						293,770
Changes in unrecognized amounts of pension and retiree medical benefits,net of tax of $143											208			208
Net derivative instrument fair value changes during the period, net of tax of $615											888			888
Unrealized loss - marketable securities, net of tax of $284											411			411
Comprehensive income for the period														295,277
Common dividends declared to parent								(232,709	)					(232,709	)
Contribution of capital by parent						112,736								112,736
Balance at Dec. 31, 2009		1,000,000	$	10	$	2,028,593	$	1,210,894		$	1,712		$	3,241,209
Net income								274,225						274,225
Changes in unrecognized amounts of pension and retiree medical benefits,net of tax of $(30)											(43	)		(43	)
Net derivative instrument fair value changes during the period, net of tax of $717											1,036			1,036
Unrealized loss - marketable securities,net of tax of $89											129			129
Comprehensive income for the period														275,347
Common dividends declared to parent								(233,181	)					(233,181	)
Contribution of capital by parent						212,794								212,794
Balance at Dec. 31, 2010		1,000,000	$	10	$	2,241,387	$	1,251,938		$	2,834		$	3,496,169

See Notes to Consolidated Financial Statements

Index

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars)

	Dec. 31,
	2010			2009
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 1, 2010, 4.75%	$	-		$	175,000
Aug. 28, 2012, 8%		450,000			450,000
Aug. 15, 2015, 1.95%		250,000			-
March 1, 2018, 5.25%		500,000			500,000
March 1, 2019, 8.5% (a)		27,900			27,900
Sept. 1, 2019, 8.5% (a)		100,000			100,000
July 1, 2025, 7.125%		250,000			250,000
March 1, 2028, 6.5%		150,000			150,000
April 1, 2030, 8.5% (a)		69,000			69,000
July 15, 2035, 5.25%		250,000			250,000
June 1, 2036, 6.25%		400,000			400,000
July 1, 2037, 6.2%		350,000			350,000
Nov. 1, 2039, 5.35%		300,000			300,000
Aug. 15, 2040, 4.85%		250,000			-
Other		32			66
Unamortized discount.		(9,020	)		(8,788	)
Total		3,337,912			3,013,178
Less current maturities		19			175,037
Total long-term debt	$	3,337,893		$	2,838,141

Common Stockholder's Equity
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2010 and 2009	$	10		$	10
Additional paid in capital		2,241,387			2,028,593
Retained earnings		1,251,938			1,210,894
Accumulated other comprehensive income		2,834			1,712
Total common stockholder's equity	$	3,496,169		$	3,241,209

(a) Pollution control financing

See Notes to Consolidated Financial Statements

Index

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 intercompany transactions and balances have been eliminated.

NSP-Minnesota has investments in several plants and transmission facilities jointly owned with other utilities. NSP-Minnesota’s share of jointly owned facilities is recorded as property, plant and equipment, consistent with industry practice. For more information, see Note 5 to the consolidated financial statements.

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 recognized. NSP-Minnesota presents its revenue net of any excise or other fiduciary-type taxes or fees.

NSP-Minnesota has various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and electric fuel costs, as well as purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. A summary of significant rate adjustment mechanisms follows:

NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy mechanism and a cost-of-gas recovery mechanism allowing 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 mechanisms for NSP-Minnesota also provide a sharing among shareholders and customers of certain margins on short-term wholesale and commodity trading.

·	NSP-Minnesota’s rates include a CIP rider for cost recovery of conservation and energy management program costs as well as recovery of a financial incentive for meeting energy savings goals.

NSP-Minnesota operates under various service quality standards, which could require customer refunds if certain criteria are not met. NSP-Minnesota is allowed to recover certain costs associated with new transmission facilities through the TCR and certain costs associated with generation facilities through other rate riders.

NSP-Minnesota sells firm power and energy in wholesale markets, which are regulated by the FERC. Certain of NSP-Minnesota’s rates include monthly wholesale fuel cost-recovery mechanisms through prices that are indexed to NSP-Minnesota retail rates, including the monthly cost of fuel and purchased energy recovery mechanism.

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 NSP-Minnesota’s commodity trading margins 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 and commodity trading results include the impact of all margin-sharing mechanisms. For more information, see Note 9 to the consolidated financial statements.

Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, NSP-Minnesota may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security.

Index

Types of and Accounting for Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.

Gains or losses on hedging transactions for the sale 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; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. NSP-Minnesota is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Cash Flow Hedges — Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The accounting for derivatives 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 all hedging relationships in accordance with this guidance. The documentation includes, 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 hedging transaction. In addition, at inception and on a quarterly basis, NSP-Minnesota formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. NSP-Minnesota discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis. Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case, associated deferred amounts are immediately recognized in current earnings.

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for the purchase and sale of commodities for use in their business operations. Derivatives and hedging accounting guidance 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 derivative accounting as normal purchases or normal sales.

NSP-Minnesota evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

For further discussion of NSP-Minnesota’s risk management and derivative activities, see Note 9 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. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs 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 include costs associated with property held for future use.

Index

NSP-Minnesota records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic 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, 2010, 2009 and 2008 was 3.4, 3.2 and 3.6 percent, respectively.

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

Generally AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases the MPUC has approved a more current recovery of cost associated with large capital projects, resulting in a lower recognition of AFUDC. One of these projects was recently completed. The MERP project converted two coal-fueled electric generating plants located in the Minneapolis-St. Paul metropolitan area to natural gas and installed advanced pollution control equipment at a third coal-fired plant. 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 AFUDC. Other projects that have construction costs with current recovery include certain wind and transmission projects.

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 generally determined based on quoted market prices for those or similar investments. The fair values for commingled funds and international equity funds within the external nuclear decommissioning fund take into consideration the value of underlying fund investments. For more information on nuclear decommissioning, see Note 13 to the consolidated financial statements.

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 AFUDC), as well as future disposal costs of spent nuclear fuel and costs associated with the end-of-life fuel segments.

Nuclear Refueling Outage Costs —NSP-Minnesota uses a deferral and amortization method for nuclear refueling O&M costs. This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates.

Leases — NSP-Minnesota evaluates a variety of contracts for lease classification at inception, including purchased power agreements and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease.

Variable Interest Entities — Effective Jan. 1, 2010, NSP-Minnesota adopted new guidance on consolidation of variable interest entities. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

Under its purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants. Through various mechanisms in certain purchased power agreements, NSP-Minnesota incurs variable fuel costs, and consequently these mechanisms have been determined to create variable interests in the independent power producing entities. Certain independent power producing entities are therefore variable interest entities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated. Costs are 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.

Index

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 — Litigation accruals are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated. External legal fees related to settlements are expensed as incurred.

Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. NSP-Minnesota uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

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

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 14 to the consolidated financial statements. For more information on income taxes, see Note 6 to the consolidated financial statements.

NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that NSP-Minnesota has taken or expects to take in its income tax returns. In accordance with this guidance, NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

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

Xcel Energy and its subsidiaries, including NSP- Minnesota, file consolidated federal income tax returns and combined and separate state income tax returns. Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings. The holding company also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries.

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, AROs, 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 becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed annually 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 is recorded at average cost.

Regulatory Accounting — NSP-Minnesota accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

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

Index

·	Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

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 treatment in the rate setting process.

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-offs are recorded. See more discussion of regulatory assets and liabilities in Note 14 to the consolidated financial statements.

Conservation Programs — NSP-Minnesota has implemented programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include, but are not limited to, commercial process efficiency and lighting updates, and residential rebates for participation in air conditioning interruption and energy-efficient appliances.

The costs incurred for CIP programs are deferred if it is probable that future revenue, in an amount at least equal to the deferred amount, will be provided to permit recovery of the previously incurred cost, rather than to provide for expected future amounts of similar programs. For incentive programs designed to allow recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within twenty four months following the end of the annual period in which they are earned.

NSP-Minnesota’s CIP program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage NSP-Minnesota’s achievement of energy conservation goals and to compensate for related lost sales margin. NSP-Minnesota recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Deferred Financing Costs — Other assets included deferred financing costs of approximately $27.2 million and $23.7 million, net of amortization, at Dec. 31, 2010 and 2009, respectively. NSP-Minnesota is amortizing these financing costs over the remaining maturity periods of the related debt.

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

Guarantees — NSP-Minnesota recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligations that have been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as NSP-Minnesota is released from risk under the guarantee. Refer to Note 10 to the consolidated financial statements for specific details of issued guarantees.

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

Renewable Energy Credits — RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Currently, NSP-Minnesota acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchased as a result of meeting load obligations, they are recorded as inventory at cost. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues, net of any margin sharing requirements.

Index

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. NSP-Minnesota follows the inventory accounting model for all emission allowances. The sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows

Reclassifications — Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to deferred income taxes, regulatory assets and regulatory liabilities in the consolidated balance sheet and consolidated statements of cash flows. These reclassifications did not have an impact on net income.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2010 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2.	Accounting Pronouncements

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the ASC were effective for interim and annual periods beginning after Nov. 15, 2009. NSP-Minnesota implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures regarding variable interest entities, see Note 12 to the consolidated financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. NSP-Minnesota implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures, see Note 9 to the consolidated financial statements.

3.	Selected Balance Sheet Data

	Dec. 31,
(Thousands of Dollars)	2010			2009
Accounts receivable, net
Accounts receivable	$	334,481		$	322,778
Less allowance for bad debts		(20,996	)		(22,675	)
	$	313,485		$	300,103
Inventories
Materials and supplies	$	122,706		$	105,508
Fuel		95,804			99,705
Natural gas		61,663			50,706
	$	280,173		$	255,919
Property, plant and equipment, net
Electric plant	$	10,563,424		$	9,679,288
Natural gas plant		979,256			948,708
Common and other property		510,577			472,624
Construction work in progress		695,292			587,080
Total property, plant and equipment		12,748,549			11,687,700
Less accumulated depreciation		(5,222,980	)		(5,030,836	)
Nuclear fuel		1,837,697			1,737,469
Less accumulated amortization		(1,541,046	)		(1,435,677	)
	$	7,822,220		$	6,958,656

Index

4.	Borrowings and Other Financing Instruments

Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The holding company may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in the holding company.

The following table presents the money pool investments for NSP-Minnesota:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Money pool investments	$	-	$	7
Weighted average interest rate		N/A		0.36	%
Money pool borrowing limit	$	250	$	250

Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. The following table presents commercial paper outstanding for NSP-Minnesota:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Commercial paper outstanding	$	-	$	-
Weighted average interest rate		N/A		N/A
Commercial paper borrowing limit	$	482	$	482

Credit Facilities — NSP-Minnesota must have revolving credit facilities in place at least equal to the amount of its respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit agreements. All credit facility bank borrowings and outstanding commercial paper reduce the available capacity under the respective credit facilities as presented in the table below. At Dec. 31, 2010 and Dec. 31, 2009, there were no credit facility bank borrowings outstanding.

At Dec. 31, 2009, NSP-Minnesota had the following committed credit facility in effect, in millions of dollars:

Credit
Facility		Drawn*		Available		Original Term	Maturity
$	482	$	5	$	477	Five year	December 2011

* Includes outstanding letters of credit.

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. NSP-Minnesota was in compliance as its debt-to-total capitalization ratio was 49 percent and 48 percent at Dec. 31, 2010 and 2009, respectively. If NSP-Minnesota does not comply with the covenant, an event of default may be declared and it not remedied, and any outstanding amounts due under the facility can be declared due by the lender.

The credit facility has a cross default provision that provides Xcel Energy will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets of Xcel Energy on a consolidated basis, defaults on any of its indebtedness greater than $50 million.

·	The interest rate is based on the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as based on NSP-Minnesota’s applicable debt rating; this is 25 basis points.

·	The commitment fees, also based on long-term credit ratings, are calculated for the unused portion of the credit facility at 6 basis points for NSP-Minnesota.

At Dec. 31, 2010, NSP-Minnesota had no direct borrowings on this line of credit and no outstanding commercial paper; however, the credit facility was used to provide back-up support for $5.3 million of letters of credit. At Dec. 31, 2009, NSP-Minnesota had no direct borrowings on this line of credit and no outstanding commercial paper; however, the credit facility was used to provide back-up support for $5.8 million of letters of credit.

Index

Xcel Energy plans to syndicate new credit agreements at the Holding Company, NSP-Minnesota, PSCo, SPS and NSP-Wisconsin during the first quarter of 2011 to replace the existing agreements. The total anticipated size of the new credit facilities will be approximately $2.45 billion, of which $500 million relates to NSP-Minnesota.

Long-Term Borrowings

In August 2010, NSP-Minnesota issued $250 million of 1.95 percent first mortgage bonds, due Aug. 15, 2015 and $250 million of 4.85 percent first mortgage bonds, due Aug. 15, 2040. NSP-Minnesota added the net proceeds from the sale of the bonds to its general funds and applied a portion of the proceeds to the repayment of short-term debt, including short-term debt incurred to fund the repayment at maturity of $175 million of 4.75 percent first mortgage bonds due Aug. 1, 2010. The balance of the net proceeds was used for general corporate purposes, including the funding of capital expenditures.

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

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 $1.1 billion in additional cash dividends on common stock at Dec. 31, 2009 or $1.1 billion at Dec. 31, 2010.

During the next five years, NSP-Minnesota has long-term debt maturities of $450 million and $250 million due in 2012 and 2015, respectively.

5.	Joint Ownership of Generation and Transmission Facilities

Following are the investments by NSP-Minnesota in jointly owned generation and transmission facilities and the related ownership percentages as of Dec. 31, 2010:

					Construction
	Plant in		Accumulated		Work in
(Thousands of Dollars)	Service		Depreciation		Progress		Ownership %
Electric Generation:
Sherco Unit 3	$	538,043	$	350,093	$	13,494		59.0
Sherco Common Facilities Units 1, 2 and 3		126,437		79,988		5,601		75.0
Sherco Substation		4,790		2,486		-		59.0
Electric Transmission:
Grand Meadow Line and Substation		11,204		603		-		50.0
CapX2020		19,449		4,075		48,758		55.6
Total	$	699,923	$	437,245	$	67,853

NSP-Minnesota is part owner of Sherco Unit 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. CapX2020 is a joint initiative of 11 transmission-owning utilities in Minnesota and the surrounding region to expand the electric transmission grid by approximately 700 miles. The estimated cost of this initiative is $1.9 billion consisting of four major transmission projects with the goal of providing continued reliable and affordable electric service. NSP-Minnesota’s percentage ownership varies by project and its projected share of the investment is approximately $1 billion. In 2010 construction began on two of the major projects (Fargo, N.D. to Monticello, Minn. and Bemidji, Minn. to Grand Rapids, Minn. lines). In-service dates for the entire project are currently estimated to be from 2011 through 2015. Each of the respective owners is responsible for funding its portion of the construction costs.

6.	Income Taxes

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, NSP-Minnesota is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

Index

NSP-Minnesota expensed approximately $3.3 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. NSP-Minnesota does not expect the $3.3 million of additional tax expense to recur in future periods.

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expires in September 2011. The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Dec. 31, 2010, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2010, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006. In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years. After its review in the second quarter of 2010, the state of Minnesota indicated that it does not intend to perform audit procedures on these years at this time. As of Dec. 31, 2010, there were no state income tax audits in progress.

Unrecognized Tax Benefits —The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	4.0	$	2.7
Unrecognized tax benefit - Temporary tax positions		18.5		9.8
Unrecognized tax benefit balance	$	22.5	$	12.5

A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2010			2009			2008
Balance at Jan. 1	$	12.5		$	20.2		$	14.3
Additions based on tax positions related to the current year		7.3			6.9			5.4
Reductions based on tax positions related to the current year		(0.3	)		(1.4	)		(0.4	)
Additions for tax positions of prior years		3.5			3.6			4.9
Reductions for tax positions of prior years		(0.5	)		(1.5	)		-
Settlements with taxing authorities		-			(15.3	)		(4.0	)
Balance at Dec. 31	$	22.5		$	12.5		$	20.2

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryfowards are as follows:

(Millions of Dollars)		Dec. 31, 2010				Dec. 31, 2009
NOL and tax credit carryforwards		$	(11.0	)		$	(2.8	)

The increase in the unrecognized tax benefit balance of $10.0 million in 2010 was due to the addition of similar uncertain tax positions related to current and prior years’ activity. NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

Index

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2010			2009			2008
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.3	)	$	(1.3	)	$	(1.9	)
Interest income (expense) related to unrecognized tax benefits		(0.6	)		1.0			0.6
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.9	)	$	(0.3	)	$	(1.3	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2010, 2009 or 2008.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2010		2009
Federal NOL carryforward	$	407.7	$	25.8
Federal tax credit carryforwards		35.6		23.0
State tax credit carryforwards, net of federal detriment		1.8		1.8

The federal carryforward periods expire between 2021 and 2030. The state carryforward periods expire between 2017 and 2024.

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 reconciles such differences for the years ending Dec. 31:

	2010			2009			2008
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		9.2			6.2			7.6
Tax credits recognized, net of federal income tax expense		(3.1	)		(2.7	)		(1.6	)
Regulatory differences — utility plant items		(2.0	)		(1.6	)		(2.3	)
Resolution of income tax audits and other		(0.2	)		1.4			-
Change in unrecognized tax benefits		0.3			(1.0	)		0.1
Previously recognized Medicare Part D subsidies		0.7			-			-
Life insurance policies		(0.2	)		(0.3	)		(0.2	)
Other, net		0.1			0.3			(0.1	)
Effective income tax rate		39.8	%		37.3	%		38.5	%

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

(Thousands of Dollars)	2010			2009			2008
Current federal tax expense (benefit)	$	(87,554	)	$	(12,136	)	$	9,527
Current state tax expense		18,789			19,195			27,802
Current change in unrecognized tax expense (benefit)		1,850			(6,165	)		3,709
Current tax credits		(944	)		-			-
Deferred federal tax expense		215,892			154,858			122,485
Deferred state tax expense		47,092			30,364			25,653
Deferred change in unrecognized tax expense (benefit)		(577	)		1,667			(3,106	)
Deferred tax credits		(10,660	)		(9,542	)		(4,331	)
Deferred investment tax credits		(2,697	)		(3,120	)		(3,503	)
Total income tax expense	$	181,191		$	175,121		$	178,236

Index

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

(Thousands of Dollars)	2010			2009			2008
Deferred tax expense excluding items below	$	295,994		$	228,821		$	80,493
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(43,471	)		(50,432	)		55,322
Tax expense (benefit) allocated to other comprehensive income and other		(776	)		(1,042	)		4,886
Deferred tax expense	$	251,747		$	177,347		$	140,701

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

(Thousands of Dollars)	2010		2009
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,635,323	$	1,224,338
Regulatory assets		116,787		106,687
Other		19,768		26,142
Total deferred tax liabilities	$	1,771,878	$	1,357,167

Deferred tax assets:
Net operating loss carry forward		145,119		9,206
Employee benefits		56,068		63,357
Tax credit carry forward		37,403		24,831
Regulatory liabilities		17,863		16,478
Deferred investment tax credits		15,043		15,174
Bad debts		8,580		9,266
Rate refund		2,290		26,835
Other		2,745		1,247
Total deferred tax assets	$	285,111	$	166,394
Net deferred tax liability	$	1,486,767	$	1,190,773

7.	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. Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota. Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Minnesota accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy (multiple employer plans). NSP-Minnesota is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Minnesota accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Minnesota employees.

Xcel Energy, which includes NSP-Minnesota, offers various benefit plans to its employees. At Dec. 31, 2010, NSP-Minnesota had 2,060 bargaining employees covered under a collective-bargaining agreement, which expired at the end of 2010. NSP-Minnesota also had an additional 219 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expired at various dates through September 2010. As of Dec. 31, 2010, contract negotiations with the NSP-Minnesota bargaining groups were in process. On Feb. 16, 2011, the negotiations were settled via arbitration and a new collective-bargaining agreement with an expiration date of Dec. 31, 2013 went into effect.

Effective Jan. 1, 2009, Xcel Energy and NSP-Minnesota adopted new guidance on employers’ disclosures about pension and postretirement benefit plan assets. The new guidance expands employers’ disclosure requirements for benefit plan assets, including investment policies and strategies, major categories of plan assets, and information regarding fair value measurements consistent with the disclosures for entities’ recurring fair value measurements.

Index

The accounting guidance for fair value measurements establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three Levels defined by the hierarchy and examples of each Level are as follows:

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

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

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

Pension Benefits

Xcel Energy, which includes NSP-Minnesota, 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 and NSP-Minnesota’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.

Xcel Energy and NSP-Minnesota base investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider 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 portfolio of pension investments is 9.72 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2010 were above the assumed level of 7.79 percent. Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 were below the assumed level of 8.75 percent. Xcel Energy and NSP-Minnesota continually review the pension assumptions. In 2011, Xcel Energy will use an investment-return assumption of 7.50 percent.

The assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity; however, as we have experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target range pension asset allocations for 2010 and 2009:

	2010			2009
Domestic and international equity securities		24	%		24	%
Long-duration fixed income securities		41			34
Short-to-intermediate term fixed income securities		11			19
Alternative investments		17			18
Cash		7			5
Total		100	%		100	%

In 2009, Xcel Energy and NSP-Minnesota engaged J.P. Morgan’s Pension Advisory Group to evaluate the allocation of the total assets in the master pension trust, taking into consideration the funded status of each individual pension plan. The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of short-to-intermediate term and long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Index

Pension Plan Assets

The following tables present, for each of the fair value hierarchy Levels, pension plan assets that are measured at fair value as of Dec. 31, 2010 and 2009:

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	-	$	109,027		$	-	$	109,027
Short-term investments		122,643		26,683			-		149,326
Derivatives		-		8,140			-		8,140
Government securities		-		117,522			-		117,522
Corporate bonds		-		641,807			-		641,807
Asset-backed securities		-		-			26,986		26,986
Mortgage-backed securities		-		-			113,418		113,418
Common stock		117,899		-			-		117,899
Private equity investments		-		-			122,223		122,223
Commingled equity and bond funds		-		1,152,386			-		1,152,386
Real estate		-		-			73,701		73,701
Securities lending collateral obligation and other		-		(91,727	)		-		(91,727	)
Total	$	240,542	$	1,963,838		$	336,328	$	2,540,708

	Dec. 31, 2009
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	-	$	221,971		$	-	$	221,971
Short-term investments		-		324,683			-		324,683
Derivatives		-		11,606			-		11,606
Government securities		-		94,949			-		94,949
Corporate bonds		-		522,403			-		522,403
Asset-backed securities		-		-			47,825		47,825
Mortgage-backed securities		-		-			144,006		144,006
Common stock		89,260		-			-		89,260
Private equity investments		-		-			82,098		82,098
Commingled equity and bond funds		-		1,014,072			-		1,014,072
Real estate		-		-			66,704		66,704
Securities lending collateral obligation and other		-		(170,251	)		-		(170,251	)
Total	$	89,260	$	2,019,433		$	340,633	$	2,449,326

The following tables present the changes in Level 3 pension plan assets for the years ended Dec. 31, 2010 and 2009:

			Realized and			Purchases,
			Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Settlements, net			Dec. 31, 2010
Asset-backed securities	$	47,825	$	(3,678	)	$	(17,161	)	$	26,986
Mortgage-backed securities		144,006		(5,376	)		(25,212	)		113,418
Real estate		66,704		7,100			(103	)		73,701
Private equity investments		82,098		(1,032	)		41,157			122,223
Total	$	340,633	$	(2,986	)	$	(1,319	)	$	336,328

Index

			Realized and			Purchases,
			Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)			Settlements, net			Dec. 31, 2009
Asset-backed securities	$	77,398	$	48,285		$	(77,858	)	$	47,825
Mortgage-backed securities		166,610		103,470			(126,074	)		144,006
Real estate		109,289		(43,207	)		622			66,704
Private equity investments		81,034		(5,682	)		6,746			82,098
Total	$	434,331	$	102,866		$	(196,564	)	$	340,633

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)	2010			2009
Accumulated Benefit Obligation at Dec. 31	$	2,865,845		$	2,676,174

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,829,631		$	2,598,032
Service cost		73,147			65,461
Interest cost		165,010			169,790
Plan amendments		18,739			(35,341	)
Actuarial loss		169,203			223,122
Benefit payments		(225,438	)		(191,433	)
Obligation at Dec. 31	$	3,030,292		$	2,829,631

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	2,449,326		$	2,185,203
Actual return on plan assets		282,688			255,556
Employer contributions		34,132			200,000
Benefit payments		(225,438	)		(191,433	)
Fair value of plan assets at Dec. 31	$	2,540,708		$	2,449,326

Funded Status of Plans at Dec. 31:
Funded status (a)	$	(489,584	)	$	(380,305	)

NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	552,849		$	530,197
Prior service cost		37,254			34,496
Total	$	590,103		$	564,693

Amounts Related to the Funded Status of the Plans Have Been Recorded asFollows Based Upon Expected Recovery in Rates:
Regulatory assets	$	590,103		$	564,693

NSP-Minnesota accrued benefit liability recorded		196,423			157,687

Measurement date		Dec. 31, 2010			Dec. 31, 2009

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.50	%		6.00	%
Expected average long-term increase in compensation level		4.00			4.00
Mortality table		RP 2000			RP 2000

(a) Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheet.

Index

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 for 2008 through 2010 for Xcel Energy’s pension plans and are not expected to require cash funding in 2011.

Xcel Energy made total pension contributions of $34 million and $200 million during 2010 and 2009, respectively.

Voluntary contributions were made to the Xcel Energy Pension Plan of $34 million in 2010.

Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009.

Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $27 million in 2009. Voluntary contributions were made across three of Xcel Energy’s pension plans for $134 million in January 2011. The contribution raised the overall funded status from 84 percent at Dec. 31, 2010 to 88 percent with all other pension assumptions remaining constant.

Pension funding contributions for 2012, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $150 million to $175 million.

Plan Amendments — The 2010 increase of the projected benefit obligation for plan amendments is due to a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan.

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

(Thousands of Dollars)	2010			2009			2008
Service cost	$	73,147		$	65,461		$	62,698
Interest cost		165,010			169,790			167,881
Expected return on plan assets		(232,318	)		(256,538	)		(274,338	)
Amortization of prior service cost		20,657			24,618			20,584
Amortization of net loss		48,315			12,455			11,156
Net periodic pension cost (credit)	$	74,811		$	15,786		$	(12,019	)

NSP-Minnesota:
Net periodic pension cost (credit)	$	33,508		$	2,891		$	(9,034	)
(Costs) credits not recognized due to effects of regulation		(27,027	)		(2,891	)		9,034
Net benefit cost recognized for financial reporting	$	6,481		$	-		$	-

Significant Assumptions Used to Measure Costs:
Discount rate		6.00	%		6.75	%		6.25	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		7.79			8.50			8.75

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 2011 pension cost calculations will be 7.50 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including NSP-Minnesota, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

NSP-Minnesota recognizes pension expense in all regulatory jurisdictions based on the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated under accounting guidance are deferred as a regulatory asset or liability.

Xcel Energy, which includes NSP-Minnesota, also maintains 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, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for NSP-Minnesota were approximately $8.8 million in 2010, $7.5 million in 2009 and $4.2 million in 2008.

Index

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Minnesota, has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. The former NCE 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 NCE who retired after 1998 are eligible to participate in the health care program with no employer subsidy.

In 1993, Xcel Energy and NSP-Minnesota adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.

Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs. NSP-Minnesota transitioned to full accrual accounting for postretirement benefit 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 postretirement benefit costs. Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy and NSP-Minnesota base investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

The following tables present, for each of the fair value hierarchy Levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2010 and 2009:

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	72,573	$	76,352	$	-	$	148,925
Derivatives		-		13,632		-		13,632
Government securities		-		3,402		-		3,402
Corporate bonds		-		70,752		-		70,752
Asset-backed securities		-		-		2,585		2,585
Mortgage-backed securities		-		-		19,212		19,212
Preferred stock		-		507		-		507
Commingled equity and bond funds		-		102,962		-		102,962
Securities lending collateral obligation and other		-		70,253		-		70,253
Total	$	72,573	$	337,860	$	21,797	$	432,230

	Dec. 31, 2009
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	-	$	165,291	$	-	$	165,291
Short term investments		-		2,226		-		2,226
Derivatives		-		5,937		-		5,937
Government securities		-		1,538		-		1,538
Corporate bonds		-		60,416		-		60,416
Asset-backed securities		-		-		8,293		8,293
Mortgage-backed securities		-		-		47,078		47,078
Preferred stock		-		540		-		540
Commingled equity and bond funds		-		89,296		-		89,296
Securities lending collateral obligation and other		-		4,074		-		4,074
Total	$	-	$	329,318	$	55,371	$	384,689

Index

The following tables present the changes in Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2010 and 2009:

					Purchases,
			Realized and		Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Unrealized Gains		Settlements, net			Dec. 31, 2010
Asset-backed securities	$	8,293	$	1,814	$	(7,522	)	$	2,585
Mortgage-backed securities		47,078		14,715		(42,581	)		19,212

					Purchases,
			Realized and		Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Unrealized Gains		Settlements, net			Dec. 31, 2009
Asset-backed securities	$	8,705	$	1,029	$	(1,441	)	$	8,293
Mortgage-backed securities		69,988		3,022		(25,932	)		47,078

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

(Thousands of Dollars)	2010			2009
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	728,902		$	794,597
Service cost		4,006			4,665
Interest cost		42,780			50,412
Medicare subsidy reimbursements		5,423			3,226
Plan amendments		-			(27,407	)
Plan participants’ contributions		14,315			13,786
Actuarial loss (gain)		68,126			(47,446	)
Benefit payments		(68,647	)		(62,931	)
Obligation at Dec. 31	$	794,905		$	728,902

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	384,689		$	299,566
Actual return on plan assets		53,430			72,101
Plan participants’ contributions		14,315			13,786
Employer contributions		48,443			62,167
Benefit payments		(68,647	)		(62,931	)
Fair value of plan assets at Dec. 31	$	432,230		$	384,689

Funded Status of Plans at Dec. 31:
Funded status	$	(362,675	)	$	(344,213	)
Current liabilities		(5,392	)		(2,240	)
Noncurrent liabilities		(357,283	)		(341,973	)
Net postretirement amounts recognized on consolidated balance sheets	$	(362,675	)	$	(344,213	)

NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	51,208		$	49,444
Prior service credit		(1,035	)		(1,152	)
Transition obligation		2,727			4,073
Total	$	52,900		$	52,365

Index

(Thousands of Dollars)	2010			2009
Amounts Related to the Funded Status of the Plans Have Been Recorded as
Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	49,725		$	49,240
Deferred Income taxes		1,298			1,277
Net-of-tax accumulated comprehensive income		1,877			1,848
Total	$	52,900		$	52,365

NSP-Minnesota accrued benefit liability recorded	$	127,320		$	124,657

Measurement date		Dec. 31, 2010			Dec. 31, 2009

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.50	%		6.00	%
Mortality table		RP 2000			RP 2000
Health care costs trend rate - initial		6.50	%		6.80	%

Effective Dec. 31, 2010, the ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached increased from three years to eight 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:

	One Percentage Point
(Thousands of Dollars)	Increase			Decrease
APBO		$	98,812		$	(76,175	)
Service and interest components			5,006			(4,193	)

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, which includes NSP-Minnesota, contributed $48.4 million during 2010 and $62.2 million during 2009 and expects to contribute approximately $40.5 million during 2011.

Plan Amendments — No amendments occurred during 2010 to the Xcel Energy health and welfare benefit plan.

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

(Thousands of Dollars)	2010			2009			2008
Service cost	$	4,006		$	4,665		$	5,350
Interest cost		42,780			50,412			51,047
Expected return on plan assets		(28,529	)		(22,775	)		(31,851	)
Amortization of transition obligation		14,444			14,444			14,577
Amortization of prior service cost		(4,932	)		(2,726	)		(2,175	)
Amortization of net loss		11,643			19,329			11,498
Net periodic postretirement benefit cost	$	39,412		$	63,349		$	48,446

NSP-Minnesota:
Net periodic postretirement benefit cost	$	10,643		$	13,419		$	13,958

Significant Assumptions Used to Measure Costs:
Discount rate		6.00	%		6.75	%		6.25	%
Expected average long-term rate of return on assets (before tax)		7.50			7.50			7.50

Index

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
2011	$	254,426	$	59,752	$	4,770	$	54,982
2012		247,156		60,230		5,126		55,104
2013		249,908		60,607		5,475		55,132
2014		257,886		61,833		5,773		56,060
2015		259,978		63,184		6,061		57,123
2016-2020		1,338,658		325,154		34,115		291,039

8.	Other Income, Net

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

(Thousands of Dollars)	2010			2009			2008
Interest income	$	5,887		$	7,473		$	10,005
Other nonoperating (expense) income		(30	)		(6	)		1,274
Insurance policy expenses		(4,706	)		(5,895	)		(384	)
Other income, net	$	1,151		$	1,572		$	10,895

9.	Derivative Instruments and Fair Value Measurements

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices, as well as variances in forecasted weather.

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, energy and energy-related instruments. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Interest Rate Derivatives — 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 an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Dec. 31, 2010, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest transactions impact earnings.

Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale and vehicle fuel.

At Dec. 31, 2010, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2014. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2010 and Dec. 31, 2009.

At Dec. 31, 2010, accumulated OCI related to vehicle fuel cash flow hedges included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Index

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of any amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options, and FTRs at Dec. 31, 2010 and Dec. 31, 2009:

(Amounts in Thousands) (a)(b)	Dec. 31, 2010		Dec. 31, 2009
Megawatt hours (MWh) of electricity		44,376		34,374
MMBtu of natural gas		14,100		9,777
Gallons of vehicle fuel		440		2,021

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated OCI, included as a component of common stockholder’s equity, is detailed in the following table:

(Thousands of Dollars)	2010			2009			2008
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	3,941		$	3,053		$	8,704
After-tax net unrealized losses related to derivatives accounted for as hedges		(80	)		(1,219	)		(5,463	)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings		1,116			2,107			(188	)
Accumulated other comprehensive income related to cash flow hedges at Dec. 31	$	4,977		$	3,941		$	3,053

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2010 and Dec. 31, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2010 and Dec. 31, 2009, respectively, on OCI, regulatory assets and liabilities, and income:

	Dec. 31, 2010
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income (Loss)			Liabilities			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(108	)(a)	$	-		$	-
Vehicle fuel and other commodity		(137	)		-			1,998	(e)		-			-
Total	$	(137	)	$	-		$	1,890		$	-		$	-

Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	12,061	(b)
Electric commodity		-			3,969			-			(21,840	)(c)		-
Natural gas commodity		-			(18,655	)		-			9,111	(d)		-
Total	$	-		$	(14,686	)	$	-		$	(12,729	)	$	12,061

Index

	Dec. 31, 2009
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into						Pre-Tax
	During the Period in:						Income During the Period from:						Gains (Losses)
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income (Loss)			Liabilities			in Income
Derivatives designated as cash flow
hedges
Interest rate	$	(3,209	)	$	-		$	(201	)(a)	$	-		$	-
Electric commodity		-			(18,600	)		-			(4,755	)(c)		-
Natural gas commodity		-			(811	)		-			8,915	(d)		(6,951	)(d)
Vehicle fuel and other commodity		1,147			-			3,766	(e)		-			-
Total	$	(2,062	)	$	(19,411	)	$	3,565		$	4,160		$	(6,951	)(b)

Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	7,857
Electric commodity		-			20,607			-			(343	)(c)		-
Natural gas commodity		-			(373	)		-			980	(d)		-
Other		-			-			-			-			(160	)(b)
Total	$	-		$	20,234		$	-		$	637		$	7,697

(a)	Recorded to interest charges.

(b)	Recorded to electric operating revenues. Portions of these total gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

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

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

(e)	Recorded to other O&M expenses.

Credit Related Contingent Features — Contract provisions of the derivative instruments that NSP-Minnesota enters into may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. If the credit ratings were downgraded below investment grade at Dec. 31, 2010 and Dec. 31, 2009, no contracts underlying NSP-Minnesota’s derivative liabilities would require the posting of collateral or contract settlement.

Certain of NSP-Minnesota’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Dec. 31, 2010 and Dec. 31, 2009, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three Levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Index

Recurring Fair Value Measurements

The following table presents, for each of the hierarchy Levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	70	$	-	$	70	$	-		$	70
Other derivative instruments:
Trading commodity		487		31,253		-		31,740		(18,719	)		13,021
Electric commodity		-		-		3,619		3,619		(1,226	)		2,393
Natural gas commodity		-		187		-		187		(187	)		-
Total current derivative assets	$	487	$	31,510	$	3,619	$	35,616	$	(20,132	)		15,484
Purchased power agreements (b)													24,408
Current derivative instruments												$	39,892

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	83	$	-	$	83	$	-		$	83
Other derivative instruments:
Trading commodity		-		25,850		-		25,850		(2,477	)		23,373
Natural gas commodity		-		125		-		125		(48	)		77
Total noncurrent derivative assets	$	-	$	26,058	$	-	$	26,058	$	(2,525	)		23,533
Purchased power agreements (b)													77,725
Noncurrent derivative instruments												$	101,258

Other recurring fair value assets
Nuclear decommissioning fund: (a)
Cash equivalents	$	76,281	$	7,556	$	-	$	83,837	$	-	$	83,837
Commingled funds		-		133,080		-		133,080		-		133,080
International equity funds		-		58,584		-		58,584		-		58,584
Debt securities:								-
Government securities		-		146,654		-		146,654		-		146,654
U.S. corporate bonds		-		288,304		-		288,304		-		288,304
Foreign securities		-		1,581		-		1,581		-		1,581
Municipal bonds		-		97,557		-		97,557		-		97,557
Asset-backed securities		-		-		33,174		33,174		-		33,174
Mortgage-backed securities		-		-		72,589		72,589		-		72,589
Equity securities - Common stock		435,270		-		-		435,270		-		435,270
Total nuclear decommissioning fund	$	511,551	$	733,316	$	105,763	$	1,350,630	$	-	$	1,350,630

Index

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total

Current derivative liabilities
Other derivative instruments:
Trading commodity	$	392	$	25,416	$	-	$	25,808	$	(21,337	)	$	4,471
Electric commodity		-		-		1,227		1,227		(1,227	)		-
Natural gas commodity		20		9,156		-		9,176		(187	)		8,989
Total current derivative liabilities	$	412	$	34,572	$	1,227	$	36,211	$	(22,751	)		13,460
Purchased power agreements (b)													13,851
Current derivative instruments												$	27,311

Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,351	$	-	$	13,351	$	(2,478	)	$	10,873
Natural gas commodity		-		75		-		75		(48	)		27
Total noncurrent derivative liabilities	$	-	$	13,426	$	-	$	13,426	$	(2,526	)		10,900
Purchased power agreements (b)													186,871
Noncurrent derivative instruments												$	197,771

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $15.4 million of miscellaneous investments.

(b)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power 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 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer 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 assets and liabilities.

(c)

The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

NSP-Minnesota recognizes transfers between Levels as of the beginning of each period. The following table presents the transfers that occurred between Levels during the year ended Dec. 31, 2010.

(Thousands of Dollars)	From Level 3 to Level 2
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	5,384
Noncurrent assets		21,450
Current liabilities		(2,851	)
Noncurrent liabilities		(12,345	)
Total	$	11,638

There were no transfers of amounts from Level 2 to Level 3, or any transfers to or from Level 1 for the year ended Dec. 31, 2010. The transfer of amounts from Level 3 to Level 2 is due to the valuation of certain long term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

Index

The following tables present, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2009:

	Dec. 31, 2009
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative assets
Other derivative instruments:
Trading commodity	$	-	$	13,748	$	6,253	$	20,001	$	(11,640	)	$	8,361
Electric commodity		-		-		23,540		23,540		1,425			24,965
Natural gas commodity		-		1,580		-		1,580		54			1,634
Total current derivative assets	$	-	$	15,328	$	29,793	$	45,121	$	(10,161	)		34,960
Purchased power agreements (b)													24,522
Current derivative instruments												$	59,482

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	85	$	-	$	85	$	-		$	85
Other derivative instruments:
Trading commodity		-		7,040		11,610		18,650		(4,193	)		14,457
Natural gas commodity		-		31		-		31		1			32
Total noncurrent derivative assets	$	-	$	7,156	$	11,610	$	18,766	$	(4,192	)		14,574
Purchased power agreements (b)													102,642
Noncurrent derivative instruments												$	117,216


Other recurring fair value assets
Nuclear decommissioning fund: (a)
Cash equivalents	$	-	$	28,134	$	-	$	28,134	$	-		$	28,134
Debt securities:
Government securities		-		74,126		-		74,126		-			74,126
U.S. corporate bonds		-		312,844		-		312,844		-			312,844
Foreign securities		-		9,445		-		9,445		-			9,445
Municipal bonds		-		149,088		-		149,088		-			149,088
Asset-backed securities		-		-		11,918		11,918		-			11,918
Mortgage-backed securities		-		-		81,189		81,189		-			81,189
Equity securities - Common stock		581,995		-		-		581,995		-			581,995
Total nuclear decommissioning fund	$	581,995	$	573,637	$	93,107	$	1,248,739	$	-		$	1,248,739

Index

	Dec. 31, 2009
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	1,905	$	-	$	1,905	$	-		$	1,905
Other derivative instruments:
Trading commodity		-		14,248		3,731		17,979		(15,503	)		2,476
Electric commodity		-		-		3,276		3,276		1,425			4,701
Natural gas commodity		-		640		-		640		54			694
Other commodity		-		-		360		360		-			360
Total current derivative liabilities	$	-	$	16,793	$	7,367	$	24,160	$	(14,024	)		10,136
Purchased power agreements (b)													14,525
Current derivative instruments												$	24,661

Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	4,895	$	6,799	$	11,694	$	(4,197	)	$	7,497
Natural gas commodity		-		364		-		364		1			365
Total noncurrent derivative liabilities	$	-	$	5,259	$	6,799	$	12,058	$	(4,196	)		7,862
Purchased power agreements (b)													201,666
Noncurrent derivative instruments												$	209,528

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $17.0 million of miscellaneous investments.

(b)

(c)

The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options. Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers. Electric commodity derivatives include FTRs, for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

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

Index

Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including money market funds, are also monitored as additional support for determining fair value. Equity securities are valued using quoted prices in active markets. The fair values for commingled funds and international equity funds are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value. Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated principal prepayments. Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2010, 2009 and 2008:

	Year Ended Dec. 31,
(Thousands of Dollars)	2010			2009			2008
Balance at Jan. 1	$	27,237		$	23,247		$	15,345
Purchases and settlements, net		(393	)		(476	)		(1,585	)
Transfers (out of) into Level 3		(11,638	)		700			(2,578	)
(Losses) gains recognized in earnings		(16,576	)		(3,115	)		496
Gains recognized as regulatory assets and liabilities		3,762			6,881			11,569
Balance at Dec. 31	$	2,392		$	27,237		$	23,247

Losses on Level 3 commodity derivatives recognized in earnings for the years ended Dec. 31, 2010 and Dec. 31, 2009, include $4.7 million and $5.7 million of net unrealized gains, respectively, relating to commodity derivatives held at Dec. 31, 2010 and Dec. 31, 2009. Gains on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2008, include $2.9 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2008. Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or deferred as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a regulatory asset for nuclear decommissioning.

The following table presents the changes in Level 3 nuclear decommissioning fund assets for the years ended Dec. 31, 2010, 2009 and 2008:

	Year Ended Dec. 31,
	2010							2009								2008
	Mortgage-				Asset-			Mortgage-				Asset-				Mortgage-				Asset-
	Backed				Backed			Backed				Backed				Backed				Backed
(Thousands of Dollars)	Securities				Securities			Securities				Securities				Securities				Securities
Balance at Jan. 1		$	81,189			$	11,918		$	98,461			$	10,962			$	100,802			$	7,854
Purchases and settlements, net			(12,204	)			20,993			(27,872	)			(484	)			7,907				4,291
Gains (losses) recognized as regulatory assets and liabilities			3,604				263			10,600				1,440				(10,248	)			(1,183	)
Balance at Dec. 31		$	72,589			$	33,174		$	81,189			$	11,918			$	98,461			$	10,962

10.	Financial Instruments

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

	2010				2009
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Nuclear decommissioning fund	$	1,350,630	$	1,350,630	$	1,248,739	$	1,248,739
Other investments		50		50		695		695
Long-term debt, including current portion		3,337,912		3,673,214		3,013,178		3,238,854

Index

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 external nuclear decommissioning trust fund investments are generally estimated based on quoted market prices for those or similar investments. The fair values for commingled funds and international equity funds take into consideration the value of underlying fund investments. The fair value of NSP-Minnesota’s 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, 2010 and 2009. 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.

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, 2010 and 2009, there were $6.4 million and $6.9 million letters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

11.	Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — MPUC

Base Rate

NSP-Minnesota Electric Rate Case — In November 2010, NSP-Minnesota filed a request with the MPUC to increase annual electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent. The rate filing is based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent. In January 2011, NSP-Minnesota revised its requested 2011 rate increase to $148.3 million as the result of the sale of certain transmission assets.

NSP-Minnesota requested an additional increase of $48.3 million or 1.81 percent effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012. Additionally, NSP-Minnesota seeks to transfers approximately $158 million already collected from ratepayers through riders into base rates at the conclusion of this case with implementation of final rates.

The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. The interim rates remain in effect until the MPUC makes its final decision on the case. An MPUC decision is anticipated in the fourth quarter of 2011. The following procedural schedule has been established:

Intervenor direct testimony due April 5, 2011;

Rebuttal testimony due May 4, 2011;

Surrebuttal testimony due May 26, 2011;

Evidentiary hearings due June 1-8, 2011;

Initial brief due July 29, 2011;

Reply brief and findings due Aug. 19, 2011;

ALJ report Sept. 19, 2011; and

MPUC order due Nov. 28, 2011.

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010, based on an ROE of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million. In December 2009, the MPUC approved an interim rate increase of $11.1 million, subject to refund. Interim rates went into effect on Jan. 11, 2010.

In June 2010, NSP-Minnesota revised its request to an increase of $10.0 million based on an ROE of 10.6 percent. In November 2010, the MPUC authorized a rate increase of approximately $7 million based on an ROE of 10.0 percent.

Index

Electric, Purchased Gas and Resource Adjustment Clauses

TCR Rider — The MPUC has approved a TCR rider that allows annual adjustments to retail electric rates to provide recovery of certain incremental transmission investments between rate cases. In 2010, the MPUC approved a TCR rider that recovered approximately $10.8 million during 2010. In October 2010, NSP-Minnesota filed its 2011 rider recovery request, seeking approval to recover approximately $12.9 million during 2011. The request is pending MPUC action.

RES Rider — The MPUC has approved a RES rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES. In 2010, the MPUC approved a RES rider that resulted in $38.4 million in revenue recovery during 2010. In October 2010, NSP-Minnesota filed its 2011 rider recovery request, seeking approval to recover approximately $67.8 million during 2011.

MERP Rider — In December 2009, the MPUC authorized NSP-Minnesota to recover revenue requirements related to environmental improvement projects of approximately $116.7 million during 2010 through the MERP rider. In October 2010, NSP-Minnesota filed a request to recover approximately $111.4 million during 2011. Final MPUC action is pending; however, NSP-Minnesota is allowed to implement the 2011 adjustment prior to MPUC approval. If the approval is for a different amount, any under- or over-collections would be trued up in the next annual period.

CIP Rider — CIP expenses are recovered through a charge embedded in base rates and a rider that is adjusted annually. In April 2010, NSP-Minnesota filed its annual rider petitions requesting recovery of approximately $45 million of electric CIP expenses and financial incentives and $10.2 million of natural gas CIP expenses and financial incentives. These amounts correspond to the forecasted unrecovered year-end balances. During the proceedings, the OES recommended that cost recovery be accelerated and increased to reduce the unrecovered balances and the associated carrying charges assessed to customers on the balances. This would result in higher rider rates in the short-term, but future rates would be lower as the unrecovered balance was lowered.

In October 2010, the MPUC approved an increase to the electric CIP rider rate to increase cost recovery and reduce the unrecovered CIP balance to approximately zero by the end of 2012. Based on the higher rate, NSP-Minnesota estimates recovery of $66.7 million through the rider during the November 2010 to September 2011 timeframe. This is in addition to an expected $48.1 million through the conservation cost recovery charge component of base rates.

In November 2010, the MPUC approved an increase to the natural gas CIP rider rate to increase cost recovery and reduce the unrecovered balance to approximately zero by the end of 2011. Based on the higher rate, NSP-Minnesota estimates recovery of approximately $18.6 million through the natural gas CIP rider during the December 2010 to September 2011 timeframe. This is in addition to an expected $3.0 million through the conservation cost recovery charge component of base rates.

Pending and Recently Concluded Regulatory Proceedings — NDPSC

North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent. NSP-Minnesota requested an additional increase of $4.2 million, or 2.6 percent, effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. The interim rates would remain in effect until the NDPSC makes its final decision on the case, which is anticipated in the fourth quarter of 2011.

The schedule is as follows:

Intervenor direct testimony due June 20, 2011;

Rebuttal testimony due July 22, 2011;

Evidentiary hearings due Aug. 9-12, 2011;

Initial briefs due Sept. 16, 2011;

Reply brief and findings due Sept. 30, 2011; and

NDPSC order due Nov. 16, 2011.

Index

Pending and Recently Concluded Regulatory Proceedings — FERC

Rate Increase for Grandfathered Transmission Service Customers — In May 2010, NSP-Minnesota filed to revise the rate applicable to eight wholesale customers taking transmission service under a “grandfathered” 1998 rate schedule (known as Tm-1). The change would set the Tm-1 transmission service rate equal to the similar rate under the MISO Tariff, and would increase Tm-1 rates by about $5 million annually (a 120 percent increase). NSP-Minnesota proposed the rate change be accepted effective Aug. 1, 2010, but placed into effect Jan. 1, 2011. The affected Tm-1 customers intervened in the rate filing and protested the increase. In July 2010, the FERC accepted the rate filing and allowed the rates to go into effect on Jan. 1, 2011, subject to refund and settlement judge procedures. In December 2010, NSP-Minnesota and Tm-1 customer reached a settlement in principle which will result in an increase of approximately $3.5 million annually. NSP-Minnesota anticipates the settlement agreement will be filed with the FERC in first quarter 2011. The settlement agreement must be approved before it is effective. On Jan. 11, 2011, NSP-Minnesota filed for authorization to place the settlement rates into effect on an interim basis, subject to FERC approval of the settlement. The FERC ALJ granted the motion on Jan. 19, 2011.

12.	Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2010, the estimated cost of capital expenditure programs of NSP-Minnesota is approximately $1.3 billion in 2011, $1.1 billion in 2012 and $1.5 billion in 2013. NSP-Minnesota’s capital forecast includes the following major projects.

Nuclear Capacity Increases and Life Extension — NSP-Minnesota is seeking a 20-year license renewal for the Prairie Island nuclear plant. A renewed operating license was approved and issued for Monticello by the NRC in November 2006 licensing the plant to operate until 2030, and the MPUC order approving the spent fuel storage capacity needed to support plant operations until 2030 went into effect in June 2007. The application to renew Prairie Island’s operating licenses was submitted to the NRC in April 2008 and a final decision is expected in early 2011. The application for a CON for additional spent fuel storage capacity to support 20 additional years of plant operation was approved by the MPUC in December 2009.

NSP-Minnesota is pursuing capacity increases of Monticello and Prairie Island that will total approximately 235 MW, to be implemented, if approved, between 2010 and 2015. Total capital investment between 2011 and 2015 for these activities is estimated to be approximately $725 million to bring the total investment to over $1 billion. The MPUC approved the Monticello power uprate CON and site permit in December 2008 and the Prairie Island power uprate CON and site permit in December 2009. The filing for the Monticello power uprate was placed on hold by the NRC staff to address concerns raised by the ACRS related to containment pressure associated with pump performance. NSP-Minnesota is working with the NRC to determine whether if needs to supplement its filing as necessary to address the issues and expects to complete the license proceeding in 2011. NSP-Minnesota cannot file for NRC approval of the extended power uprate for Prairie Island until after the NRC renews the plants’ current operating licenses. A decision is expected in 2011. The extended power uprates are scheduled to be implemented during the 2014 and 2015 refueling outages.

CapX2020 — In 2006, CapX2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified several groups of transmission projects that proposed to be complete by 2020. Group 1 project investments are expected to total approximately $1.9 billion. Major construction began in 2010 and on two of the four Group 1 projects, with the in-service date of the last project expected to be in 2015. Xcel Energy’s investment is expected to be approximately $1.0 billion depending on the routes and configurations approved by affected state commissions. The remainder of the costs will be born by other utilities in the upper Midwest. Approximately 75 percent of the 2010 capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota TCR tariff rider mechanism authorized by Minnesota legislation, as well as a similar TCR mechanism passed in South Dakota. Cost-recovery by NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.

Black Dog Repowering — NSP-Minnesota is proposing construction over the next five years to repower the Black Dog generating plant in Burnsville, Minn. The $585 million project will replace the remaining coal-fired units and install approximately 680 MW of natural gas generation in 2016. The new gas-fired generation is a combined-cycle facility consisting of two combustion turbines and one steam turbine.

Index

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, legislative initiatives, reserve margins, the availability of purchased power, alternative plans for meeting NSP-Minnesota’s long-term energy needs, compliance with future requirements and RPS to install emission-control equipment and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

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 2011 and 2029. 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 to customers.

The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2010, is as follows:

(Millions of Dollars)	2010
Coal	$	1,577.3
Nuclear fuel		1,170.1
Natural gas supply		129.6
Natural gas storage and transportation		907.9

Purchased Power Agreements — NSP-Minnesota has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2034. In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for purchase power agreements accounted for as executory contracts were payments for capacity of $109.3 million, $109.3 million and $111.5 million in 2010, 2009 and 2008, respectively. At Dec. 31, 2010, the estimated future payments for capacity that NSP-Minnesota is obligated to purchase, subject to availability, were as follows:

(Millions of Dollars)
2011	$	107.9
2012		106.7
2013		109.0
2014		111.3
2015		83.9
2016 and thereafter		239.3
Total *	$	758.1

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

Leases — NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases. Total expenses under operating lease obligations was approximately $73.0 million, $76.2 million and $70.7 million for 2010, 2009 and 2008, respectively. These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchase power agreements accounted for as operating leases of $57.1 million, $56.2 million and $48.6 million in 2010, 2009 and 2008, respectively.

Index

Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating leases are:

(Millions of Dollars)	Other Operating Leases		Purchase Power Agreement Operating Leases (a) (b)		Total Operating Leases
2011	$	12.4	$	54.1	$	66.5
2012		9.9		55.0		64.9
2013		9.3		55.9		65.2
2014		8.9		56.8		65.7
2015		8.1		57.8		65.9
Thereafter		44.5		616.3		660.8

(a) Amounts not included in purchase power agreement estimated future payments above.

(b) Purchase power agreement operating leases contractually expire through 2025.

Variable Interest Entities — Effective Jan. 1, 2010, NSP-Minnesota adopted new guidance on consolidation of variable interest entities. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants. Under certain purchased power agreements with these entities, NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that NSP-Minnesota purchases. These specific purchased power agreements have been determined by NSP-Minnesota to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.

NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

NSP-Minnesota has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, historical and estimated future fuel and electricity prices, and financing activities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. As of Dec. 31, 2010 and Dec. 31, 2009, NSP-Minnesota had approximately 1,064 MW of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

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 PRPs 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 — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination. Environmental contingencies could arise from various situations including sites of former manufactured gas plants operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes. At Dec. 31, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.4 million and $0.3 million, respectively, of which $0.3 million and $0.2 million, respectively, was considered to be a current liability.

Index

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 ARO. See additional discussion of AROs below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing 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

EPA GHG Endangerment Rulemaking — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare, and that emissions from motor vehicles contribute to the GHGs in the atmosphere. The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations became applicable in 2011. In December 2010, the EPA announced a settlement with several states and environmental groups to begin preparing regulations of emissions from both new and existing steam electric generating units, such as coal-fired power plants, under Section 111 of the CAA. The EPA plans to propose these regulations in July 2011 and finalize them in the first half of 2012.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota. In 2008, the U.S. Court of Appeals for the District of Columbia vacated and remanded CAIR.

In July 2010, the EPA issued the proposed CATR, which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia. The EPA is proposing to reduce these emissions through federal implementation plans for each affected state. The EPA’s preferred approach would set emission limits for each state and allow limited interstate emissions trading. As proposed, CATR will impact Minnesota for annual SO2 and NOx emissions. NSP-Minnesota is analyzing the proposed rule to determine whether emission reductions are needed from its facilities. Until CATR becomes final, NSP-Minnesota will continue activities to support CAIR compliance. In 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective in December 2009. Cost estimates are therefore not included at this time for NSP-Minnesota.

CAMR — In 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize MACT emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR. NSP-Minnesota anticipates that the EPA will require affected facilities to demonstrate compliance within three to five years. Costs associated with such requirements are uncertain at this time.

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

In November 2008, the MPUC approved the implementation of the Sherco Unit 3 and A.S. King mercury emission reduction plans. A sorbent injection control system was installed at Sherco Unit 3 in December 2009, and installation of a sorbent injection system was completed at A.S. King scheduled in December 2010. In 2010, NSP-Minnesota collected the revenue requirements associated with these projects through the MCR rider. In the 2010 Minnesota electric general rate case, NSP-Minnesota proposed moving the costs of these projects into base rates as part of the interim rates effective on Jan. 2, 2011. Concurrent with the implementation of interim rates, the MCR rider will be reduced to zero.

In December 2009, NSP-Minnesota filed its mercury control plan at Sherco Units 1 and 2 with the MPUC and the MPCA. In October 2010, the MPUC approved the plan, which will require installation of mercury controls on Sherco Units 1 and 2 by the end of 2014.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules including provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States.

NSP-Minnesota submitted its BART alternatives analysis to the MPCA for Sherco Units 1 and 2 in 2006. The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART. The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft SIP that are equivalent to the reductions made under CAIR.

Index

In October 2009, the U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by MPCA is appropriate.

The MPCA determined that this certification does not alter the proposed SIP. The SIP proposes BART controls for the Sherco generating facilities that are designed to improve visibility in the national parks, but does not require SCR on Units 1 and 2. The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs. In December 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval. Until the EPA takes final action on the SIP, the total cost of compliance cannot be estimated with a reasonable degree of certainty.

Federal CWA — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the BTA for minimizing adverse environmental impacts. In 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 challenging the phase II rulemaking. In April 2009, the U.S. Supreme Court issued a decision concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required that the plant submit a plan for compliance with the CWA. The compliance plan was submitted for MPCA review and approval in April 2010. The MPCA is currently reviewing the proposal in consultation with the EPA. NSP-Minnesota anticipates a decision on the plan by the end of 2011.

Proposed Coal Ash Regulation — Xcel Energy’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, Xcel Energy’s costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted. Xcel Energy submitted comments to the EPA on Nov. 19, 2010 indicating its support of the development of regulations to manage coal ash as a nonhazardous waste. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

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 the applicable accounting guidance. 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.

Recorded ARO — AROs have been recorded for plant related to nuclear production, steam production, wind production, electric transmission and distribution, gas transmission and distribution and office buildings. The steam production obligation includes asbestos, ash containment facilities, radiation sources 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 CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs 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. Additional AROs have been recorded for NSP-Minnesota steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.

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 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.

Index

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. See Note 13 to the consolidated financial statements for further discussion of nuclear obligations.

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s AROs is shown in the table below for the 12 months ended Dec. 31, 2010 and Dec. 31, 2009, respectively:

	Beginning									Revisions			Ending
	Balance		Liabilities		Liabilities					to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2010		Recognized		Settled			Accretion		Estimates			Dec. 31, 2010
Electric plant
Steam production asbestos	$	16,776	$	3,771	$	(2,330	)	$	858	$	(9,034	)	$	10,041
Steam production ash containment		12,547		-		-			611		(344	)		12,814
Steam production radiation sources		57		-		-			3		(23	)		37
Nuclear production decommissioning		758,923		-		-			50,551		-			809,474
Wind production		7,751		25,671		-			592		4,539			38,553
Electric transmission and distribution		140		-		-			7		2,940			3,087
Natural gas plant
Gas transmission and distribution		261		-		-			17		-			278
Common and other property
Common general plant asbestos		1,021		-		-			56		-			1,077
Total liability	$	797,476	$	29,442	$	(2,330	)	$	52,695	$	(1,922	)	$	875,361

The fair value of NSP-Minnesota assets legally restricted, for purposes of settling the nuclear AROs, is $1.4 billion as of Dec. 31, 2010, including external nuclear decommissioning investment funds and internally funded amounts.

In 2010 and 2009, NSP-Minnesota incurred revisions for asbestos, radiation sources, wind turbines, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates. In 2009, revisions were made for nuclear plants.

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

The revised end of life date for the Prairie Island nuclear plant approved by the MPUC in 2008 and effective Jan. 1, 2009 resulted in the nuclear production decommissioning ARO and related regulatory asset decreasing by $315.9 million in 2009.

Index

Removal Costs — NSP-Minnesota records a regulatory liability 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 estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2010 and 2009 were $400 million and $372 million, respectively.

Nuclear Insurance

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $12.6 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $12.2 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 $117.5 million per reactor per accident 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 $17.5 million per reactor during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective October 2008. The next adjustment is due on or before October 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business 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 $15.8 million for business interruption insurance and $32.6 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of NSP-Minnesota, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. 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 September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds. In August 2010, this decision was reversed by the Second Circuit and is currently on appeal before the United States Supreme Court. Oral arguments will be presented to the Supreme Court on April 19, 2011 and a decision is expected in the summer of 2011.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of NSP-Minnesota, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege 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. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs’ subsequent appeals of this decision were unsuccessful, therein rendering the district court’s dismissal the final determination.

Index

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of NSP-Minnesota, and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008. In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. It is unknown when the Ninth Circuit will render a final opinion. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs alleged relocation is estimated to cost between $95 million to $400 million. No accrual has been recorded for this matter.

13.	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 KWh sold to customers from nuclear generation. Fuel expense includes the DOE fuel disposal assessments of approximately $13 million in 2010, $12 million in 2009 and $13 million 2008, respectively. In total, NSP-Minnesota had paid approximately $410.7 million to the DOE through Dec. 31, 2010. The Nuclear Waste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. 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 and dry cask facilities at both sites. The amount of spent fuel storage capacity currently authorized by the NRC and the MPUC will allow NSP-Minnesota to continue operation of its Prairie Island nuclear plant until the end of its renewed licenses terms, when approved by the NRC in 2011, and its Monticello nuclear plant until the end of its renewed operating license in 2030. Other 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.

Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the period from cessation of operations through 2067, assuming the prompt dismantlement method. NSP-Minnesota is currently recording 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 ARO in accordance with the applicable accounting guidance.

Monticello received its initial operating license in 1970 and began operation in 1971. With its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation, Monticello can operate until 2030. The Monticello 20-year depreciation life extension until September 2030 was granted by the MPUC in 2007. Construction of the Monticello dry-cask storage facility is complete, and 10 of the 30 canisters authorized have been filled and placed in the facility.

Prairie Island Units 1 and 2 received their initial operating licenses and began commercial operation in 1973 and 1974, respectively, and are currently licensed to operate until 2013 and 2014, respectively. In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island that will allow operation for an additional 20 years until 2033 and 2034, respectively. The NRC staff is proceeding with the remaining items necessary to process Prairie Island’s license renewal application and NSP-Minnesota anticipates receiving a final decision on the Prairie Island license renewal in 2011. Prairie Island’s depreciation life, as approved by the MPUC in June 2010, is currently 2024. The Prairie Island dry-cask storage facility currently stores 29 casks to support operations until the end of the current operating licenses in 2013 and 2014. The MPUC approved the use of 35 additional casks to support operations until the end of the renewed operating licenses (once received from the NRC) in 2033 and 2034.

The total obligation for decommissioning currently is expected to be funded 100 percent by the external decommissioning trust fund, as approved by the MPUC, when decommissioning commences. The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in October 2009, using 2008 cost data. The next study update will be submitted in October 2011 for the 2012 accrual. The MPUC approval, eliminated 2009 decommissioning funding for Minnesota retail customers, due to a full extension of the accrual period for the Monticello unit from 2020 to 2030, along with an extension of the accrual period for Prairie Island (from 2013 for Unit 1 and 2014 for Unit 2 to 2023 and 2024 respectively). In November 2009, the MPUC also approved a proposal to refund the Minnesota portion of the Monticello escrow fund in a supplemental filing.

Index

Consistent with cost-recovery in utility customer rates, NSP-Minnesota previously recorded 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. The most recent study, which resulted in an authorization of no funding, presumes that costs will escalate in the future at a rate of 2.89 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by the external decommissioning trust fund, 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 6.30 percent, net of tax, for external funding. The net unrealized loss on nuclear decommissioning investments is deferred as a regulatory liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

The external funds are held in trust and in escrow. The portion in escrow is subject to refund if approved by the various commissions. The MPUC authorized the return of $23.5 million of funds associated with the Monticello plant for the Minnesota retail jurisdictions. This amount was withdrawn in December 2009 and was refunded on customers’ bills in February 2010. An amount of approximately $5.9 million was also withdrawn from the Monticello plant portion of the escrow fund in March 2010 in preparation for a refund to Wisconsin and Michigan retail customers. The funds have not yet been refunded as of Dec. 31, 2010, and the timing of the refunds will be determined in future rate cases in each jurisdiction.

At Dec. 31, 2010, NSP-Minnesota recorded and recovered in rates cumulative decommissioning expense of $1.4 billion. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters from the most recently approved decommissioning study. Xcel Energy believes future decommissioning cost expense, if necessary, will continue to be recovered in customer rates. These amounts are not those recorded in the financial statements for the ARO.

(Thousands of Dollars)	2010			2009
Estimated decommissioning cost obligation (2008 dollars)	$	2,308,196		$	2,308,196
Effect of escalating costs (to 2010 and 2009 dollars, respectively, at 2.89 percent per year)		135,342			66,707
Estimated decommissioning cost obligation (in current dollars)		2,443,538			2,374,903
Effect of escalating costs to payment date (2.89 percent per year)		2,672,825			2,741,460
Estimated future decommissioning costs (undiscounted)		5,116,363			5,116,363
Effect of discounting obligation (using risk-free interest rate)		(3,856,516	)		(3,973,493	)
Discounted decommissioning cost obligation		1,259,847			1,142,870
Assets held in external decommissioning trust		1,350,630			1,248,739
Excess assets in external trust compared to discounted decommissioning obligation	$	(90,783	)	$	(105,869	)

Decommissioning expenses recognized include the following components:

(Thousands of Dollars)	2010			2009			2008
Annual decommissioning cost expense reported as depreciation expense:
Externally funded	$	934		$	2,849		$	43,239
Internally funded (including interest costs)		(777	)		(884	)		(819	)
Net decommissioning expense recorded	$	157		$	1,965		$	42,420

Reductions to expense for internally-funded portions in 2010, 2009 and 2008 are a direct result of the 2008 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the remaining operating life of the unit. The 2008 nuclear decommissioning filing approved in 2009 has been used for the regulatory presentation. The change in estimated decommissioning obligations was calculated using a cost estimate for Monticello assuming a 60-year operating life.

Nuclear Decommissioning Fund — The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities, and other funds - all classified as available-for-sale securities under the applicable accounting guidance. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

Index

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Deferred unrealized gains for the nuclear decommissioning fund were $82.5 million and $74.4 million at Dec. 31, 2010 and 2009, respectively, and unrealized losses and amounts recorded as other than temporary impairments were $65.2 million and $138.7 million at Dec. 31, 2010 and 2009, respectively.

The following tables present the cost and fair value of the investments in the nuclear decommissioning fund, by asset class on Dec. 31, 2010 and 2009:

	2010				2009
			Fair				Fair
(Thousands of Dollars)	Cost		Value		Cost		Value
Cash equivalents	$	83,837	$	83,837	$	28,134	$	28,134
Commingled funds		131,000		133,080		-		-
International equity funds		54,561		58,584		-		-
Equity securities - Common stock		436,334		435,270		662,655		581,995
Debt securities
Government securities		146,473		146,654		74,162		74,126
U.S. corporate bonds		279,028		288,304		299,259		312,844
Foreign securities		1,233		1,581		9,269		9,445
Municipal bonds		100,277		97,557		147,689		149,088
Asset-backed securities		32,558		33,174		11,565		11,918
Mortgage-backed securities		68,072		72,589		80,276		81,189
Total nuclear decommissioning fund	$	1,333,373	$	1,350,630	$	1,313,009	$	1,248,739

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class for the year ended Dec. 31, 2010:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	301	$	117,041	$	15,270	$	14,042	$	146,654
U.S. corporate bonds		3,071		71,615		178,067		35,551		288,304
Foreign securities		-		1,581		-		-		1,581
Municipal bonds		-		-		50,729		46,828		97,557
Asset-backed securities		-		22,232		10,942		-		33,174
Mortgage-backed securities		-		-		1,249		71,340		72,589
Debt securities	$	3,372	$	212,469	$	256,257	$	167,761	$	639,859

Index

14.	Regulatory Assets and Liabilities

NSP-Minnesota’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1 to the consolidated financial statements. Under this guidance, 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 establish regulatory assets and liabilities. If changes in the utility industry or the business of NSP-Minnesota no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in its consolidated statement of income.

The components of regulatory assets and liabilities shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2010 and Dec. 31, 2009 are:

	See	Remaining
(Thousands of Dollars)	Note(s)	Amortization Period	Dec. 31, 2010				Dec. 31, 2009
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Recoverable purchased natural gas and electric energy costs	1	One to two years	$	7,475	$	9,907	$	30,428	$	10,620
Pension and employee benefit obligations (a)	7	Various		43,289		198,173		32,905		155,234
AFUDC recorded in plan (b)	1	Plant lives		-		150,857		-		133,602
Contract valuation adjustments (c)	9	Term of related contract		-		107,526		-		89,026
Net AROs (d)	1,12	Plant lives		-		88,804		-		155,773
Conservation programs (b)	1,11	One to two years		43,497		31,401		33,276		12,752
Nuclear outage costs	1	One to two years		33,819		7,169		57,707		3,040
Renewable and environmental initiative costs	11,12	One to three years		25,365		10,268		35,371		6,564
Purchased power contracts costs	9	Term of related contract		-		25,915		-		20,014
Losses on reacquired debt	1	Term of related debt		2,110		18,978		2,417		21,088
MISO Day 2 costs		One to two years		3,277		3,277		3,276		6,553
Nuclear fuel storage	12,13	One to two years		2,529		3,250		2,522		5,779
State commission adjustments (b)	1	Plant lives		-		5,120		-		4,631
Other		Various		3,582		10,746		2,364		3,149
Total regulatory assets			$	164,943	$	671,391	$	200,266	$	627,825

Regulatory Liabilities
Deferred electric and gas production costs	1		$	14,651	$	-	$	-	$	-
Plant removal costs	1,12			-		400,233		5,915		365,952
Deferred income tax adjustment	1			-		29,814		-		32,792
Investment tax credit deferrals	1			-		25,438		-		25,659
Renewable environmental initiative	11			14,752		-		-		-
Nuclear outage costs				3,441		3,441		3,441		6,881
Contract valuation adjustments (c)	9			2,393		-		20,871		-
Other				6,885		3,648		3,631		4,627
Total regulatory liabilities			$	42,122	$	462,574	$	33,858	$	435,911

(a)

Includes $400.2 million and $427.2 million for the regulatory recognition of pension expense at Dec. 31, 2010 and Dec. 31, 2009, respectively. These amounts are offset by $1.8 million and $1.4 million of regulatory assets related to the non-qualified pension plan of which $0.2 million is included in the current asset at Dec. 31, 2010 and Dec. 31, 2009, respectively.

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

(c)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.

(d)	Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

Index

15.	Segments and Related Information

NSP-Minnesota has the following reportable segments: regulated electric, regulated natural gas and all other.

NSP-Minnesota’s regulated electric utility segment 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 segment 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.

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of NSP-Minnesota. 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 is separately determined for each segment.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2010
Operating revenues from external customers	$	3,624,715	$	589,044	$	20,557		$	-		$	4,234,316
Intersegment revenues		420		4,377		-			(4,797	)		-
Total revenues	$	3,625,135	$	593,421	$	20,557		$	(4,797	)	$	4,234,316

Depreciation and amortization	$	364,104	$	36,623	$	409		$	-		$	401,136
Interest charges and financing cost		165,099		17,090		111			-			182,300
Income tax expense		162,931		10,957		7,303			-			181,191
Net income		250,166		23,474		585			-			274,225

2009
Operating revenues from external customers	$	3,407,273	$	640,323	$	19,093		$	-		$	4,066,689
Intersegment revenues		414		1,799		-			(2,213	)		-
Total revenues	$	3,407,687	$	642,122	$	19,093		$	(2,213	)	$	4,066,689

Depreciation and amortization	$	353,089	$	35,854	$	424		$	-		$	389,367
Interest charges and financing cost		160,091		16,608		349			-			177,048
Income tax expense (benefit)		167,708		11,677		(4,264	)		-			175,121
Net income		261,556		21,881		10,333			-			293,770

Index

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2008
Operating revenues from external customers	$	3,584,109	$	889,958	$	19,569		$	-		$	4,493,636
Intersegment revenues		564		4,863		-			(5,427	)		-
Total revenues	$	3,584,673	$	894,821	$	19,569		$	(5,427	)	$	4,493,636

Depreciation and amortization	$	376,768	$	35,209	$	385		$	-		$	412,362
Interest charges and financing cost		162,697		17,464		1,068			-			181,229
Income tax expense (benefit)		167,961		12,509		(2,234	)		-			178,236
Net income		250,785		28,887		5,469			-			285,141

16.	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. See Note 4 for further discussion of this borrowing arrangement.

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)	2010		2009		2008
Operating revenues:
Electric	$	416,076	$	389,023	$	390,143
Gas		163		309		312
Operating expenses:
Purchased power		68,224		64,059		64,195
Transmission expense		48,088		45,192		42,167
Other operating expenses — paid to Xcel Energy Services Inc.		338,676		303,348		275,618
Interest expense		178		596		1,645
Interest income		69		50		2,536

Accounts receivable and payable with affiliates at Dec. 31 were:

	2010				2009
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Wisconsin	$	26,864	$	-	$	31,243	$	-
PSCo		-		6,674		-		15,789
SPS		-		1,610		-		2,268
Other subsidiaries of Xcel Energy		2		53,469		2		65,702
	$	26,866	$	61,753	$	31,245	$	83,759

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, 2010 and 2009, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $37.0 million and $15.5 million, respectively.

Index

17.	Summarized Quarterly Financial Data (Unaudited)

Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results. Summarized quarterly unaudited financial data is as follows:

	Quarter Ended
(Thousands of Dollars)	March 31, 2010		June 30, 2010		Sept. 30, 2010		Dec. 31, 2010
Operating revenues	$	1,127,107	$	916,290	$	1,130,913	$	1,060,006
Operating income		142,000		107,362		217,674		131,188
Net income		64,139		44,040		109,787		56,259

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

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

During 2009 and 2010, 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 SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2010, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Controls Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Minnesota has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2010 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

This annual report does not include an attestation report of NSP-Minnesota’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit NSP-Minnesota to provide only management’s report in this annual report.

Item 9B — Other Information

None.

Index

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 and Related Transactions, and Director Independence

Item 14 — Principal Accountant 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 2011 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements:

	Management Report on Internal Controls — For the year ended Dec. 31, 2010.
	Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2010, 2009 and 2008.
	Consolidated Statements of Income — For the three years ended Dec. 31, 2010, 2009 and 2008.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2010, 2009 and 2008.
	Consolidated Balance Sheets — As of Dec. 31, 2010 and 2009.

2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2010, 2009 and 2008.

3.	Exhibits

*Indicates incorporation by reference

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

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of NSP-Minnesota (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.03*	By-Laws of NSP-Minnesota as Amended and Restated (a Minnesota corporation) (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034). Supplemental Indentures between NSP-Minnesota and said Trustee, dated as follows:
	Supplemental Indenture dated June 1, 1995, creating $250,000,000 principal amount of 7.125 percent First Mortgage Bonds, Series due July 1, 2025 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995, Rider A).
	Supplemental Indenture dated April 1, 1997, creating $100,000,000 principal amount of 8.5 percent First Mortgage Bonds, Series due Sept. 1, 2019 and $27,900,000 principal amount of 8.5 percent First Mortgage Bonds, Series due March 1, 2019 (Exhibit 4.47 to Form 10-K (file no. 001-03034) dated Dec. 31, 1997.)
	Supplemental Indenture dated March 1, 1998, creating $150,000,000 principal amount of 6.5 percent First Mortgage Bonds, Series due March 1, 2028 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998, Rider A).

Index

4.02*	Supplemental Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.03*	Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.04*	Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee (Assignment and Assumption of Indenture). (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.05*	Supplemental Indenture dated July 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $69,000,000 principal amount of 8.5 percent First Mortgage Bonds, Series due April 1, 2030 (Exhibit 4.06 to NSP-Minnesota Current Report on Form 10-Q, (file no. 000-31387) dated Sept. 30, 2002).
4.06*	Supplemental Trust Indenture dated Aug. 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $450,000,000 principal amount of 8.0 percent First Mortgage Bonds, Series due Aug. 28, 2012 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated Aug. 22, 2002).
4.07*	Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated July 14, 2005).
4.08*	Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated May 18, 2006).
4.09*	Supplemental Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
4.10*	Supplemental Indenture dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust Company, NA, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008.
4.11*	Supplemental Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300,000,000 principal amount of 5.35 percent First Mortgage Bonds, Series due Sept. 1, 2039 (Exhibit 4.01 of Form 8-K of NSP-Minnesota dated Nov. 16, 2009 (file no. 001-31387)).
4.12*	Supplemental Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250,000,000 principal amount of 1.950 percent First Mortgage Bonds, Series due Aug. 15, 2015 and $250,000,000 principal amount of 4.850 percent First Mortgage Bonds, Series due Aug. 15, 2040. (Exhibit 4.01 to Form 8-K dated Aug. 11, 2010 (file no. 001-31387)).
10.01*+	Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+	Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Amended and Restated Executive Long-Term Incentive Award Stock Plan (Exhibit 10.02 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+	New Century Energies Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+	Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to
	Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+	Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+	Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.14*+	Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).

Index

10.15*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*	Ownership and Operating Agreement, dated March 11, 1982, between NSP-Minnesota, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3 (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.17*	Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.18*	Amendment dated as of April 13, 2009 to the NSP-Minnesota Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.19*	Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.20*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy. (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.21*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.22*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.23*+	Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.24*+	Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.25*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.26*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement 2 (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.27*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.28*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
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.

Index

SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2010, 2009 and 2008

(amounts in thousands of dollars)

			Additions
	Balance at Jan. 1		Charged to costs and expenses		Charged to other accounts (a)		Deductions from reserves (b)		Balance at Dec. 31
Reserve deducted from related assets:
Allowance for bad debts:
2010	$	22,675	$	15,213	$	5,805	$	22,697	$	20,996
2009		25,699		19,408		5,521		27,953		22,675
2008		20,103		25,506		6,113		26,023		25,699

(a)	Recovery of amounts previously written off.

(b)	Principally bad debts written off or transferred.

Index

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/ DAVID M. SPARBY
	David M. Sparby
	Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)

Feb. 28, 2011

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 Feb. 28, 2011.

/s/ JUDY M. POFERL		/s/ RICHARD C. KELLY
Judy M. Poferl		Richard C. Kelly
President, Chief Executive Officer and Director		Chairman and Director
(Principal Executive Officer)

/s/ TERESA S. MADDEN		/s/ DAVID M. SPARBY
Teresa S. Madden		David M. Sparby
Vice President and Controller		Vice President, Chief Financial Officer and Director
(Principal Accounting Officer)		(Principal Financial Officer)

/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
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.

NORTHERN STATES POWER CO - FORM 10-K - February 28, 2011

Attached files

NORTHERN STATES POWER CO Reports