NORTHERN STATES POWER CO /WI/ - FORM 10-K

Attached files

file	filename
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO /WI/	ex32_01.htm
EX-23.01 - EXHIBIT 23.01 - NORTHERN STATES POWER CO /WI/	ex23_01.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO /WI/	ex31_02.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO /WI/	ex31_01.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO /WI/	ex99_01.htm
EX-12.01 - EXHIBIT 12.01 - NORTHERN STATES POWER CO /WI/	ex12_01.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-03140

Northern States Power Company

(Exact name of registrant as specified in its charter)

Wisconsin

(State or other jurisdiction of incorporation or organization)

39-0508315

(I.R.S. Employer Identification No.)

1414 West Hamilton Avenue

Eau Claire, Wisconsin 54701

(Address of principal executive offices)

Registrant’s telephone number, including area code: 715-839-2625

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes x 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. o Large accelerated filer o Accelerated filer x Non-accelerated filer (Do not check if a smaller reporting company) o 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 February 28, 2011, 933,000 shares of common stock, par value $100 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).

TABLE OF CONTENTS

Index


PART I		3
Item 1 — Business		3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS		3
COMPANY OVERVIEW		6
ELECTRIC UTILITY OPERATIONS		6
Overview		6
Public Utility Regulation		7
Capacity and Demand		8
Energy Sources and Related Transmission Initiatives		8
Fuel Supply and Costs		9
Fuel Sources		9
Summary of Recent Federal Regulatory Developments		10
Electric Operating Statistics		13
NATURAL GAS UTILITY OPERATIONS		13
Public Utility Regulation		13
Capability and Demand		14
Natural Gas Supply and Costs		14
Natural Gas Operating Statistics		15
ENVIRONMENTAL MATTERS		15
EMPLOYEES		15
Item 1A — Risk Factors		16
Item 1B — Unresolved Staff Comments		24
Item 2 — Properties		24
Item 3 — Legal Proceedings		25
Item 4 — Reserved		25

PART II		25
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		25
Item 6 — Selected Financial Data		25
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Item 7A — Quantitative and Qualitative Disclosures About Market Risk		28
Item 8 — Financial Statements and Supplementary Data		29
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		68
Item 9A — Controls and Procedures		68
Item 9B — Other Information		68

PART III		68
Item 10 — Directors, Executive Officers and Corporate Governance		68
Item 11 — Executive Compensation		68
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		68
Item 13 — Certain Relationships and Related Transactions, and Director Independence		68
Item 14 — Principal Accountant Fees and Services		69

PART IV		69
Item 15 — Exhibits, Financial Statement Schedules		69

SIGNATURES		72

This Form 10-K is filed by NSP-Wisconsin. NSP-Wisconsin 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.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates (current and former)
NCE		New Century Energies, Inc.
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
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
MPSC		Michigan Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.
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 U.S. 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.
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.
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources
Electric, Purchased Gas and Resource Adjustment Clauses
DSM		Demand side management. Energy conservation, weatherization and other programs to conserve or manage energy use by customers.
FCA		Fuel clause adjustment. A clause included in electric rate schedules that provides for monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.

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Other Terms and Abbreviations
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.
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
BACT	Best Available Control Technology
BRIGO	Buffalo Ridge Incremental Generation Outlet
CO2	Carbon dioxide
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
Codification	FASB Accounting Standards Codification
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
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
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
GHG	Greenhouse gas
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.
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services Inc.
MRO	Midwest Reliability Organization
MVP	Multi-Value Project

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native load		The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas		A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
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
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.
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SO2		Sulfur dioxide
Standard & Poor’s		Standard & Poor’s Ratings Services
unbilled revenues		Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying		A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission		An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.

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

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COMPANY OVERVIEW

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of its total sales in 2010. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory. NSP-Wisconsin provides electric utility service to approximately 250,000 customers and natural gas utility service to approximately 106,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2010. Generally, NSP-Wisconsin’s earnings contribute approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, 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. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

NSP-Wisconsin 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 13 to the accompanying consolidated financial statements.

NSP-Wisconsin 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-Wisconsin 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-Wisconsin. 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-Wisconsin 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 these policies on NSP-Wisconsin will depend on the specifics of state and federal policies and legislation, and regulation, we believe that, based on prior state commission practice, NSP-Wisconsin would be granted the authority to recover the cost of these initiatives through rates.

Utility Competition — The FERC has continued its efforts to promote competitive wholesale markets through open-access transmission and other means. As a consequence, NSP-Wisconsin and its wholesale customers 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.

The FERC approved the open access transmission planning processes for the MISO and the RTO serving the NSP System. In 2002, NSP-Wisconsin began providing its Michigan electric customers with the opportunity to select an alternative electric energy provider. To date, no NSP-Wisconsin customers have selected an alternative electric energy provider.

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Alternative Energy Options — NSP-Wisconsin’s industrial and large commercial customers have the 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, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While NSP-Wisconsin faces these challenges, it believes its rates are competitive with currently available alternatives. In December 2010, NSP-Wisconsin’s two largest wholesale customers, the cities of Rice Lake, Wis. and Medford, Wis., each issued a notice canceling their wholesale power contracts with NSP-Wisconsin. The two cities will begin purchasing power from an alternate supplier. Medford will terminate service at the end of 2011, and Rice Lake will terminate service at the end of 2012. In 2009, these two customers represented over half of NSP-Wisconsin’s wholesale load and revenue, and approximately 3 percent of NSP-Wisconsin’s total electric operating revenue.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce. NSP-Wisconsin has 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-owning member of the MISO RTO.

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.

Bay Front Biomass Gasification — In December 2009, the PSCW granted NSP-Wisconsin a certificate of authority to install biomass gasification technology at the Bay Front Power Plant in Ashland, Wis. The initial estimate required for the additional biomass receiving and handling facilities at the plant, an external gasifier, minor modifications to the plant’s remaining coal-fired boiler and an enhanced air quality control system was approximately $58 million.

In the second quarter of 2010, NSP-Wisconsin completed a more detailed analysis of the project and estimated the project cost increased to nearly $79.5 million, well above the 10 percent cost tolerance band allowed by the PSCW in the certificate of authority final order. In November 2010, NSP-Wisconsin notified the PSCW that it planned to discontinue the Bay Front Gasifier Project. This decision was based on higher estimated costs for all biomass combustion technologies, reduced costs for alternative renewable energy generation and regulatory uncertainty at the federal and state level. In December 2010, NSP-Wisconsin received notification from the PSCW that the Bay Front Gasifier Project docket had been closed and no outstanding compliance requirements existed. NSP-Minnesota has withdrawn the rate recovery filings previously submitted to the MPUC and the NDPSC.

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with costs included in retail base electric rates. If the comparison results in a difference of 2 percent, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward. Any revised rates would remain in effect until the next rate change. The adjustment approved is calculated on an annual basis, but applied prospectively. NSP-Wisconsin’s wholesale electric rate schedules include a FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. In 2011, the fuel and purchased energy cost recovery mechanism will be changed as discussed below.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Wisconsin Fuel Cost Recovery Legislation — In May 2010, Wisconsin adopted a law to modify its existing statutes and rules governing electric fuel cost recovery in utility rates. The prohibition on an automatic adjustment clause remains, but the provision requiring an emergency or extraordinary increase in the cost of fuel before the PSCW can approve a fuel-related rate increase was repealed.

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Under the final rules, an electric utility will submit a forward-looking annual fuel cost plan for approval by the PSCW. Once a utility has an approved fuel cost plan, it can then defer any under-collection or over-collection of fuel costs for future rate recovery or refund, for the amount of any under/over-collection that exceeds a 2 percent symmetrical annual tolerance band. Approval of a fuel cost plan and any rate adjustment for recovery or refund of deferred costs would be determined by the PSCW after opportunity for a hearing. Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE. The rule went into effect for calendar year 2011.

Wisconsin RPS and Energy Efficiency and Conservation Goals — The Wisconsin legislature passed an RPS that requires 10 percent of electric sales statewide to be supplied by renewable energy sources by the year 2015. However, under the RPS, each individual utility must increase its renewable percentage by 6 percent over its baseline level. For NSP-Wisconsin, the RPS is 12.89 percent. NSP-Wisconsin anticipates it will meet the RPS requirements with its pro-rata share of existing and planned renewable generation on the NSP System.

In 2010, the Wisconsin legislature approved a recommendation by the PSCW to increase state energy efficiency and conservation funding. NSP-Wisconsin will be allocated approximately $9.6 million of the statewide program costs for 2011. Historically, NSP-Wisconsin has recovered these costs in rates it charges to Wisconsin retail customers and expects to recover the increased program costs in rates going forward. The new statewide annual funding requirements are fixed as follows:

(Millions of Dollars)
2011	$	120
2012		160
2013		204
2014 and thereafter		256

Regulatory Investigations

ARCs — In 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers unless the applicable state regulatory authority prohibits ARCs from serving retail customers in their state. ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Wisconsin. 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. During 2009, the PSCW and MPSC issued orders temporarily prohibiting ARCs from operating in Wisconsin and Michigan, respectively, pending further regulatory proceedings. No additional action has been taken by the PSCW or the MPSC since that time.

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 2010, 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.

Energy Sources and Related Transmission Initiatives

The NSP System expects to use existing electric generating stations, power purchases, DSM options, new generation facilities and phased expansion of existing generation at select power plants to meet its system capacity requirements.

Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota 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 from a particular generating source and a charge for the associated energy actually purchased from such generating source.

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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-Wisconsin and NSP-Minnesota 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 provide for the purchase of 850 MW, which start to expire April 30, 2015. NSP-Minnesota filed for approval with the MPUC in June 2010.

NSP-Minnesota filed its 2011 through 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 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.

As noted above, the electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, and the costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin under a FERC-approved Interchange Agreement. Therefore, the Minnesota resource plan and decisions have a direct impact on the costs that are shared by NSP-Wisconsin.

Fuel Supply and Costs

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


NSP System Generating Plants	Coal*					Nuclear					Natural Gas					Weighted 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.

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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.

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.

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-Wisconsin, and enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Wisconsin’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 10 to the consolidated financial statements for a discussion of other regulatory matters.

FERC 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.

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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

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 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, the FERC issued an order accepting the NERC approval with no further action.

In March 2010, the MRO conducted a 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.

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 penalties may be assessed against NSP-Wisconsin 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 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 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 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.

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 $1.8 million. NSP-Wisconsin will seek recovery through applicable ratemaking 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. Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then subjected to those rates.

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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 as a 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. In December 2010, the FERC approved the tariff revisions, with conditions, to be effective in July 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.

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.

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.

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Electric Operating Statistics

	Year Ended Dec. 31,
	2010			2009			2008

Electric sales (Millions of KWh)
Residential		1,962			1,897			1,938
Commercial and industrial		4,320			4,221			4,391
Public authorities and other		35			38			38
Total retail		6,317			6,156			6,367
Sales for resale		546			531			553
Total energy sold		6,863			6,687			6,920

Number of customers at end of period
Residential		210,781			210,109			209,980
Commercial and industrial		37,873			37,662			37,315
Public authorities and other		1,151			1,163			1,154
Total retail		249,805			248,934			248,449
Wholesale		10			10			10
Total customers		249,815			248,944			248,459

Electric revenues (Thousands of Dollars)
Residential	$	213,060		$	201,756		$	200,982
Commercial and industrial		335,725			318,645			320,804
Public authorities and other		5,241			5,585			5,420
Total retail		554,026			525,986			527,206
Wholesale		33,471			29,649			32,768
Interchange revenues from NSP-Minnesota		116,312			109,251			106,363
Other electric revenues		4,370			6,817			(962	)
Total electric revenues	$	708,179		$	671,703		$	665,375

KWh sales per retail customer		25,288			24,730			25,627
Revenue per retail customer	$	2,218		$	2,113		$	2,122
Residential revenue per KWh		10.86	¢		10.64	¢		10.37	¢
Commercial and industrial revenue per KWh		7.77			7.55			7.31
Wholesale revenue per KWh		6.13			5.58			5.93

NATURAL GAS UTILITY OPERATIONS

The most significant developments in the natural gas operations of NSP-Wisconsin are the continued volatility in natural gas market prices, safety requirements for natural gas pipelines and the continued trend toward declining use per residential customer, as well as small commercial and industrial customers (C&I), as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2010, average annual sales to the typical NSP-Wisconsin residential customer declined from 85 MMBtu per year to 70 MMBtu per year, and to a typical small C&I customer declined from 491 MMBtu per year to 460 MMBtu per year, on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of gas cost-recovery mechanisms, high prices can encourage further efficiency efforts by customers.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Wisconsin is subject to the U.S Department of Transportation, the PSCW and the MPSC for pipeline safety compliance.

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Natural Gas Cost-Recovery Mechanisms — NSP-Wisconsin has a retail purchased gas adjustment cost-recovery mechanism for Wisconsin operations to recover changes in the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

NSP-Wisconsin’s natural gas rate schedules for Michigan customers include a natural gas cost-recovery factor, which is based on 12-month projections.

For further discussion, see Note 10 to the consolidated financial statements.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 146,018 MMBtu for 2010, which occurred on Dec. 14, 2010.

NSP-Wisconsin 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 approximately 134,736 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 27 percent of winter natural gas requirements and 39 percent of peak day firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 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-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2010-2011 supply plan was approved by the PSCW in October 2010.

Natural Gas Supply and Costs

NSP-Wisconsin 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-Wisconsin conducts natural gas price hedging activity that has been approved by the PSCW. 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-Wisconsin’s regulated retail natural gas distribution business:

2010	$	5.46
2009		5.85
2008		8.54

The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment mechanisms. NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2011 through 2032.

NSP-Wisconsin 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-Wisconsin was committed to approximately $114 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 12 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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

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Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2010			2009			2008

Natural gas deliveries (Thousands of MMBtu)
Residential		6,278			6,825			7,155
Commercial and industrial		8,063			8,656			8,921
Total retail		14,341			15,481			16,076
Transportation		3,827			3,775			3,828
Interdepartment deliveries		669			374			443
Total deliveries		18,837			19,630			20,347

Number of customers at end of period
Residential		93,402			92,484			91,593
Commercial and industrial		12,288			12,190			12,132
Total retail		105,690			104,674			103,725
Transportation and other		22			22			22
Total customers		105,712			104,696			103,747

Natural gas revenues (Thousands of Dollars)
Residential	$	59,675		$	66,003		$	87,944
Commercial and industrial		56,218			62,577			90,211
Total retail		115,893			128,580			178,155
Transportation and other		2,183			2,975			1,279
Total natural gas revenues	$	118,076		$	131,555		$	179,434

MMBtu sales per retail customer		135.69			147.90			154.99
Revenue per retail customer	$	1,097		$	1,228		$	1,718
Residential revenue per MMBtu		9.51	¢		9.67	¢		12.29	¢
Commercial and industrial revenue per MMBtu		6.97			7.23			10.11
Transportation and other revenue per MMBtu		0.57			0.79			0.33

ENVIRONMENTAL MATTERS

NSP-Wisconsin’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-Wisconsin has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. NSP-Wisconsins facilities have been designed and constructed to operate in compliance with applicable environmental standards.

NSP-Wisconsin 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-Wisconsin’s operations. For more information on environmental contingencies, see Note 11 to the consolidated financial statements.

EMPLOYEES

The number of full-time NSP-Wisconsin employees at Dec. 31, 2010 and 2009 was 559 and 561, respectively. Of these full-time employees, 402, or 72 percent and 405, or 72 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-Wisconsin and are not considered in the above amounts.

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Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes NSP-Wisconsin, 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, we are 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. Crosscutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and NSP-Wisconsin’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 such as 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 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-Wisconsin’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. In addition to the code of conduct, we have a robust compliance program, including policies, training and reporting options. 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-Wisconsin’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. 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 of 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 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 prices 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 as part of our local gas distribution company supply 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.

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 share in the electric production and transmission costs of the NSP-Minnesota system, which is integrated with our system. Accordingly, our costs may be increased due to increased costs associated with NSP-Minnesota’s system.

Our electric production and transmission system is managed on an integrated basis with the electric production and transmission system of NSP-Minnesota. As discussed above, pursuant to the Interchange Agreement between NSP-Minnesota and us, we share, on a proportional basis, all costs related to the generation and transmission facilities of the entire integrated NSP System, including capital costs. Accordingly, if the costs to operate the NSP System increase, or revenue decreases, whether as a result of state or federally mandated improvements or otherwise, our costs could also increase and our revenues could decrease and we cannot guarantee a full recovery of such costs through our rates at the time the costs are incurred.

Although we do not own any nuclear generating facilities, because our production and transmission system is operated on an integrated basis with NSP-Minnesota’s production and transmission system, we may be subject to risks associated with NSP-Minnesota’s nuclear generation.

Our electric production and transmission system is managed on an integrated basis with the electric production and transmission system of NSP-Minnesota through the Interchange Agreement.

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

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

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

●	Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of 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 NSP-Minnesota’s nuclear plants. In addition, the Institute for Nuclear Power Operations reviews NSP-Minnesota’s 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 NSP-Minnesota’s 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.

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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.

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 $73.9 million, $34.3 million and $62.5 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.

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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 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.

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 11, 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.

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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.

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 NSP-Minnesota’s nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel.

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

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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 is 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.

Item 2 — Properties

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

Electric Utility Generating Stations:

				Summer 2010
				Net Dependable
Station, Location and Unit	Fuel		Installed	Capability (MW)
Steam:
Bay Front-Ashland, Wis., 3 Units	Coal/Wood/Natural Gas		1948-1956		56
French Island-La Crosse, Wis., 2 Units	Wood/RDF	(a)	1940-1948		17
Combustion Turbine:
Flambeau Station-Park Falls, Wis	Natural Gas		1969		14
French Island-La Crosse, Wis., 2 Units	Natural Gas		1974		122
Wheaton-Eau Claire, Wis., 6 Units	Natural Gas		1973		300
Hydro:
Various locations, 63 Units	Hydro		Various		75
			Total		584

(a) 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
345 KV			1,152
161 KV			1,536
115 KV			1,736
Less than 115 KV			31,809

NSP-Wisconsin had 204 electric utility transmission and distribution substations at Dec. 31, 2010.

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Natural gas utility mains at Dec. 31, 2010:

Miles
Distribution			2,209

Item 3 — Legal Proceedings

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

Additional Information

For a discussion of legal claims and environmental proceedings, see Note 11 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 10 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-Wisconsin is a wholly owned subsidiary of Xcel Energy and there is no market for its common equity securities.

NSP-Wisconsin had dividend restrictions imposed by FERC rules and state regulatory commissions.

●	Dividends are also 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.

●	NSP-Wisconsin shall not pay dividends if its equity-to-total capitalization ratio falls below the state commission authorized level of 52.5 percent. NSP-Wisconsin’s equity-to-total capitalization ratio was 55.3 percent at Dec. 31, 2010.

The dividends declared during 2010 and 2009 were as follows:

(Thousands of Dollars)	2010		2009
First quarter	$	48,774	$	8,554
Second quarter		8,119		8,611
Third quarter		8,453		8,511
Fourth quarter		8,441		8,522

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-Wisconsin 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-Wisconsin’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 related notes to the consolidated financial statements.

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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-Wisconsin 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-Wisconsin 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-Wisconsin in reports filed with the SEC, including the items described under “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2010 and Exhibit 99.01 to NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2010.

Results of Operations

NSP-Wisconsin’s net income was approximately $42.7 million for 2010, compared with approximately $47.4 million for 2009. The decrease is primarily due to fuel recovery and higher O&M expenses, partially offset by warmer temperatures, which increased electric sales, as well as new electric rates that were effective in January 2010.

Electric Revenues and Margin

Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The electric fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction may not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings. The following table details the change in electric revenues and margin:

(Millions of Dollars)	2010			2009
Electric revenues	$	708		$	672
Electric fuel and purchased power		(400	)		(378	)
Electric margin	$	308		$	294

The following tables summarize 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
Retail rate increases	$	25
Interchange agreement billing with NSP-Minnesota		11
Estimated impact of weather		7
Sales mix and demand revenue		(6	)
Other, net		(1	)
Total increase in electric revenue	$	36

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Electric Margin

(Millions of Dollars)	2010 vs. 2009
Retail rate increases	$	25
Estimated impact of weather		7
Fuel and purchased power cost recovery		(11	)
Sales mix and demand revenue		(6	)
Other, net		(1	)
Total increase in electric margin	$	14

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details the change in natural gas revenues and margin:

(Millions of Dollars)	2010			2009
Natural gas revenues	$	118		$	132
Cost of natural gas sold and transported		(78	)		(90	)
Natural gas margin	$	40		$	42

The following tables summarize the components of the changes in natural gas revenues for the year ended Dec. 31:

Natural Gas Revenues

(Millions of Dollars)	2010 vs. 2009
Purchased natural gas adjustment clause recovery	$	(15	)
Estimated impact of weather		(2	)
Other, net		3
Total decrease in natural gas revenues	$	(14	)

Natural Gas Margin

(Millions of Dollars)	2010 vs. 2009
Estimated impact of weather	$	(2	)
Other, net		—
Total decrease in natural gas margin	$	(2	)

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Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses for 2010 increased $15.1 million, or 10.3 percent, compared with 2009. The following table summarizes the components of the changes for the year ended Dec. 31, 2010:

(Millions of Dollars)	2010 vs. 2009
Higher employee benefit costs	$	4
Higher interchange agreement billing costs with NSP-Minnesota		3
Higher plant generation costs		2
Higher contract labor costs		2
Higher labor costs		2
Higher insurance costs		2
Total increase in operating and maintenance expenses	$	15

●	Higher employee benefit costs are primarily due to increased pension costs.

●	Higher interchange costs are due to increased fixed charges.

●	Higher plant generation costs are primarily attributable to a shift in labor resources from capital to O&M.

●	Higher contract labor is primarily related to maintenance on our distribution facilities.

●	Higher labor costs are primarily due to higher overtime for storm restoration work.

●	Higher insurance costs are the result of a one-time cost reimbursement in 2009 related to a legal settlement and higher 2010 premiums.

Conservation Program Expenses — Conservation program expenses increased by approximately $2.3 million, or 21.4 percent, for 2010 compared with 2009. The higher expense is attributable to biennially approved rate orders based on the expansion of programs and regulatory commitments. Conservation program expenses are generally recovered through base rates. Overall, the program is designed to encourage NSP-Wisconsin and its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas 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.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $1.9 million, or 3.1 percent, for 2010 compared with 2009. These increases were due to normal system expansion.

Income Taxes — Income tax expense increased by approximately $0.5 million for 2010, compared with 2009. The effective tax rate was 37.9 percent for 2010, compared with 35.1 percent for 2009. The higher effective tax rate for 2010 was primarily due to decreased state unitary tax benefit in 2010.

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 5 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-Wisconsin 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. These risks, as applicable to NSP-Wisconsin, are discussed in further detail in Note 8 to the consolidated financial statements.

NSP-Wisconsin is exposed to the impact of changes in price for energy and energy related products, which is partially mitigated by NSP-Wisconsin’s use of commodity derivatives. Though no material non-performance risk currently exists with the counterparties to NSP-Wisconsin’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 securities in the master pension trust, as well as NSP-Wisconsin’s ability to earn a return on short-term investments of excess cash.

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Commodity Price Risk — NSP-Wisconsin is exposed to commodity price risk in its generation and retail distribution operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for natural gas used in distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. NSP-Wisconsin’s risk-management policy allows it to manage commodity price risk to the extent such exposure exists.

Interest Rate Risk — NSP-Wisconsin is subject to the risk of fluctuating interest rates in the normal course of business. NSP-Wisconsin’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.

Credit Risk — NSP-Wisconsin is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of their contractual obligations. NSP-Wisconsin maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At Dec. 31, 2010, a 10 percent increase in prices would have resulted in an increase in credit exposure of $0.4 million, while a decrease of 10 percent in prices would have no impact in credit exposure.

NSP-Wisconsin conducts standard credit reviews for all counterparties. NSP-Wisconsin 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 the financial markets could increase NSP-Wisconsin credit risk.

Item 8 — Financial Statements and Supplementary Data

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

See Note 15 to the consolidated financial statements for summarized quarterly financial data.

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Management Report on Internal Controls Over Financial Reporting

The management of NSP-Wisconsin is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Wisconsin’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-Wisconsin 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/ MICHAEL L. SWENSON		/S/ DAVID M. SPARBY
Michael L. Swenson		David M. Sparby
President and Chief Executive Officer		Vice President and Chief Financial Officer
February 28, 2011		February 28, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Northern States Power Company, a Wisconsin corporation

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company, a Wisconsin 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 Wisconsin 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
February 28, 2011

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2010			2009			2008
Operating revenues
Electric	$	708,179		$	671,703		$	665,375
Natural gas		118,076			131,555			179,434
Other		1,036			893			910
Total operating revenues		827,291			804,151			845,719

Operating expenses
Electric fuel and purchased power		399,740			377,784			385,180
Cost of natural gas sold and transported		78,176			90,318			136,790
Other operating and maintenance expenses		160,824			145,748			137,587
Conservation program expenses		12,965			10,679			10,170
Depreciation and amortization		63,669			61,757			58,335
Taxes (other than income taxes)		23,096			23,284			20,989
Total operating expenses		738,470			709,570			749,051

Operating income		88,821			94,581			96,668

Other income, net		1,265			727			317
Allowance for funds used during construction — equity		2,253			1,637			898

Interest charges and financing costs
Interest charges — includes other financing costs of $1,420, $1,147, and $1,325, respectively		24,517			24,782			25,641
Allowance for funds used during construction — debt		(1,039	)		(818	)		(1,053	)
Total interest charges and financing costs		23,478			23,964			24,588

Income before income taxes		68,861			72,981			73,295
Income taxes		26,112			25,618			27,774
Net income	$	42,749		$	47,363		$	45,521

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2010			2009			2008
Operating activities
Net income	$	42,749		$	47,363		$	45,521
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		64,996			62,809			61,142
Deferred income taxes		20,714			8,725			1,305
Amortization of investment tax credits		(622	)		(634	)		(629	)
Allowance for equity funds used during construction		(2,253	)		(1,637	)		(898	)
Provision for bad debts		3,294			4,505			4,784
Net realized and unrealized hedging and derivative transactions		127			1,144			457
Changes in operating assets and liabilities:
Accounts receivable		15,556			(17,905	)		10,000
Accrued unbilled revenues		(6,672	)		(2,268	)		(5,599	)
Inventories		1,827			11,033			(5,953	)
Other current assets		6,872			(9,019	)		(1,730	)
Accounts payable		(5,668	)		13,344			(1,086	)
Net regulatory assets and liabilities		(3,207	)		24,706			4,840
Other current liabilities		1,131			(10,794	)		13,470
Change in other noncurrent assets		867			822			1,733
Change in other noncurrent liabilities		2,147			(349	)		(1,023	)
Net cash provided by operating activities		141,858			131,845			126,334

Investing activities
Utility capital/construction expenditures		(128,933	)		(105,408	)		(93,736	)
Allowance for equity funds used during construction		2,253			1,637			898
Other investments		2,291			5,140			(6,565	)
Net cash used in investing activities		(124,389	)		(98,631	)		(99,403	)

Financing activities
Proceeds from notes payable to affiliate		302,300			62,500			337,600
Repayment of notes payable to affiliate		(280,850	)		(47,050	)		(396,200	)
Proceeds from issuance of long-term debt		—			—			196,370
Repayment of long-term debt, including reacquisition premiums		(95	)		(66,890	)		(80,065	)
Capital contributions from parent		40,566			21,797			8,751
Dividends paid to parent		(73,868	)		(34,259	)		(62,527	)
Net cash (used in) provided by financing activities		(11,947	)		(63,902	)		3,929

Net increase (decrease) in cash and cash equivalents		5,522			(30,688	)		30,860
Cash and cash equivalents at beginning of period		923			31,611			751
Cash and cash equivalents at end of period	$	6,445		$	923		$	31,611
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(22,154	)	$	(23,138	)	$	(20,709	)
Cash received (paid) for income taxes, net		4,371			(30,011	)		(15,768	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	3,630		$	1,800		$	2,017

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31
	2010			2009
Assets
Current assets
Cash and cash equivalents	$	6,445		$	923
Accounts receivable, net		51,664			50,069
Accounts receivable from affiliates		3			20,448
Accrued unbilled revenues		51,579			44,907
Inventories		26,616			28,443
Regulatory assets		14,084			11,341
Prepaid taxes		21,097			26,646
Deferred income taxes		—			7,356
Prepayments and other		2,555			6,507
Total current assets		174,043			196,640

Property, plant and equipment, net		1,130,342			1,059,773

Other assets
Regulatory assets		214,402			209,361
Other investments		4,036			4,287
Other		3,705			4,768
Total other assets		222,143			218,416
Total assets	$	1,526,528		$	1,474,829

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,502		$	1,365
Notes payable to affiliates		37,550			16,100
Accounts payable		35,124			36,560
Accounts payable to affiliates		36,320			38,722
Dividends payable to parent		8,441			8,522
Regulatory liabilities		10,377			19,711
Accrued interest		6,438			6,440
Taxes accrued		867			911
Derivative instruments		1,787			20
Other		17,543			15,869
Total current liabilities		155,949			144,220

Deferred credits and other liabilities
Deferred income taxes		198,793			187,027
Deferred investment tax credits		9,110			9,732
Regulatory liabilities		117,318			111,910
Environmental liabilities		97,740			95,085
Pension and employee benefit obligations		51,592			45,247
Customer advances		17,352			16,672
Other		8,142			3,884
Total deferred credits and other liabilities		500,047			469,557

Commitments and contingent liabilities
Capitalization
Long-term debt		367,854			367,978
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares		93,300			93,300
Additional paid in capital		187,071			146,505
Retained earnings		222,897			253,935
Accumulated other comprehensive loss		(590	)		(666	)
Total common stockholder’s equity		502,678			493,074
Total liabilities and equity	$	1,526,528		$	1,474,829

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN 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
					Paid In		Retained			Comprehensive			Stockholder’s
	Shares		Par Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2007		933,000	$	93,300	$	115,957	$	256,951		$	(820	)	$	465,388
Adoption of new accounting guidance for endorsement split-dollar life insurance, net of tax of $(72)								(114	)					(114	)
Net income								45,521						45,521
Net derivative instrument fair value changes during the period, net of tax of $49											78			78
Comprehensive income for 2008														45,599
Common dividends declared to parent								(61,588	)					(61,588	)
Contribution of capital by parent						8,751								8,751
Balance at Dec. 31, 2008		933,000	$	93,300	$	124,708	$	240,770		$	(742	)	$	458,036
Net income								47,363						47,363
Net derivative instrument fair value changes during the period, net of tax of $51											76			76
Comprehensive income for 2009														47,439
Common dividends declared to parent								(34,198	)					(34,198	)
Contribution of capital by parent						21,797								21,797
Balance at Dec. 31, 2009		933,000	$	93,300	$	146,505	$	253,935		$	(666	)	$	493,074
Net income								42,749						42,749
Net derivative instrument fair value changes during the period, net of tax of $51											76			76
Comprehensive income for 2010														42,825
Common dividends declared to parent								(73,787	)					(73,787	)
Contribution of capital by parent						40,566								40,566
Balance at Dec. 31, 2010		933,000	$	93,300	$	187,071	$	222,897		$	(590	)	$	502,678

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars)


		Dec. 31
		2010			2009
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
Sept. 1, 2038, 6.375%		200,000			200,000
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% (a)		18,600			18,600
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%		659			693
Other		1,954			2,015
Unamortized discount		(1,857	)		(1,965	)
Total		369,356			369,343
Less current maturities		1,502			1,365
Total long-term debt	$	367,854		$	367,978

Common Stockholder’s Equity
Common Stock — authorized 1,000,000 shares of $100 par value; outstanding 933,300 shares in 2010 and 2009	$	93,300		$	93,300
Additional paid in capital		187,071			146,505
Retained earnings		222,897			253,935
Accumulated other comprehensive loss		(590	)		(666	)
Total common stockholder’s equity	$	502,678		$	493,074

(a) Resource recovery financing

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Wisconsin is principally engaged in the generation, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. NSP-Wisconsin is subject to regulation by the FERC and state utility commissions. All of NSP-Wisconsin’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-Wisconsin has subsidiaries which have been consolidated and for which all intercompany transactions and balances have been eliminated.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. NSP-Wisconsin presents its revenue net of any excise or other fiduciary-type taxes or fees.

NSP-Wisconsin 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-Wisconsin’s retail rates in Wisconsin include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. Requests can be made for recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, or an interim fuel-cost hearing process. Effective 2011, NSP-Wisconsin will submit a forward-looking annual fuel cost plan that will allow deferral of fuel cost under-collection or over-collection, subject to PSCW hearings and approval, and other requirements. NSP-Wisconsin’s wholesale electric rate schedules include an FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

●	NSP-Wisconsin sells firm power and energy in wholesale markets, which are regulated by the FERC. Rates for these sales include monthly wholesale fuel cost-recovery mechanisms.

Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives 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-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.

Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate 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. 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 natural gas purchased for resale are recorded as a component of natural gas costs and interest rate hedging transactions are recorded as a component of interest expense. NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

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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-Wisconsin 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-Wisconsin 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-Wisconsin 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 a 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-Wisconsin 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-Wisconsin 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. For further discussion of NSP-Wisconsin’s risk management and derivative activities, see Note 8 to the consolidated financial statements.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. 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 includes costs associated with property held for future use.

NSP-Wisconsin records depreciation expense related to its plant by using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a 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, was approximately 3.5 percent for the years ended Dec. 31, 2010, 2009 and 2008.

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 other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.

Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including 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.

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Variable Interest Entities — Effective Jan. 1, 2010, NSP-Wisconsin 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-Wisconsin has entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. NSP-Wisconsin has determined its low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. NSP-Wisconsin has determined that it has the power to direct the activities that most significantly impact these entities’ economic performance, and therefore NSP-Wisconsin consolidates these limited partnerships in its consolidated financial statements.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin 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.

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-Wisconsin’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-Wisconsin 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-Wisconsin 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-Wisconsin 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-Wisconsin 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 12 to the consolidated financial statements. For more information on income taxes, see Note 5 to the consolidated financial statements.

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NSP-Wisconsin follows the applicable accounting guidance to measure and disclose uncertain tax positions that NSP-Wisconsin has taken or expects to take in its income tax returns. In accordance with this guidance, NSP-Wisconsin 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-Wisconsin 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-Wisconsin, 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-Wisconsin 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-Wisconsin 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-Wisconsin 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

●	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-Wisconsin 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-Wisconsin’s results of operations in the period the write-offs are recorded. See more discussion of regulatory assets and liabilities in Note 12 to the consolidated financial statements.

Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. NSP-Wisconsin recovers approved conservation program costs in base rate revenue.

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Deferred Financing Costs — Other assets included deferred financing costs of approximately $2.7 million and $2.9 million, net of amortization, at Dec. 31, 2010 and 2009, respectively. NSP-Wisconsin 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-Wisconsin 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-Wisconsin is released from risk under the guarantee. Refer to Note 9 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-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

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-Wisconsin 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 11 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-Wisconsin 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 8 to the consolidated financial statements.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	55,926		$	54,778
Less allowance for bad debts		(4,262	)		(4,709	)
	$	51,664		$	50,069
Inventories
Materials and supplies	$	5,564		$	4,892
Fuel		10,819			13,377
Natural gas		10,233			10,174
	$	26,616		$	28,443
Property, plant and equipment, net
Electric plant	$	1,590,713		$	1,486,696
Natural gas plant		199,224			187,459
Common and other property		123,793			109,226
Construction work in progress		42,874			52,144
Total property, plant and equipment		1,956,604			1,835,525
Less accumulated depreciation		(826,262	)		(775,752	)
	$	1,130,342		$	1,059,773

4.	Borrowings and Other Financing Instruments

NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate. The following table presents the intercompany borrowing arrangement for NSP-Wisconsin:

(Millions of Dollars)	Dec. 31, 2010			Dec. 31, 2009
Notes payable to affiliates	$	37.0		$	15.5
Weighted average interest rate		0.38	%		0.36	%
Total notes payable available for issuance	$	100		$	100

In an order dated Feb. 4, 2011, NSP-Wisconsin received regulatory approval to establish a commercial paper program authorized for $150 million and enter into a back-up credit facility. Subsequently, NSP-Wisconsin’s intercompany borrowing arrangement with NSP-Minnesota will be terminated.

The following table presents the notes payable of Clearwater Investments Inc., a NSP-Wisconsin subsidiary, to Xcel Energy:

(Millions of Dollars)	Dec. 31, 2010			Dec. 31, 2009
Notes payable to affiliates	$	0.6		$	0.6
Weighted average interest rate		0.36	%		0.37	%

Long-Term Borrowings

●	In March 2009, NSP-Wisconsin redeemed its 7.375 percent $65.0 million first mortgage bonds due Dec. 1, 2026.

●	All property of NSP-Wisconsin is subject to the lien of its first mortgage indenture.

●	During the next five years, NSP-Wisconsin has long-term debt maturities of $1.5 million due in 2011.

5.	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-Wisconsin is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

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NSP-Wisconsin expensed approximately $0.7 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. NSP-Wisconsin does not expect the $0.7 million of additional tax expense to recur in future periods.

Federal Audit — NSP- Wisconsin 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-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2010, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006. 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	$	0.2	$	0.2
Unrecognized tax benefit - Temporary tax positions		1.7		1.0
Unrecognized tax benefit balance	$	1.9	$	1.2

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	$	1.2		$	1.5		$	0.9
Additions based on tax positions related to the current year		0.7			0.6			0.5
Reductions based on tax positions related to the current year		—			(0.1	)		—
Additions for tax positions of prior years		0.1			0.3			0.1
Reductions for tax positions of prior years		(0.1	)		(0.1	)		—
Settlements with taxing authorities		—			(1.0	)		—
Balance at Dec. 31	$	1.9		$	1.2		$	1.5

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		$	(0.1	)		$	—

The increase in the unrecognized tax benefit balance of $0.7 million in 2010 was due to the addition of similar uncertain tax positions related to current and prior years’ activity. NSP-Wisconsin’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.

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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	$	—		$	(0.1	)	$	—
Interest income (expense) related to unrecognized tax benefits		(0.1	)		0.1			(0.1	)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.1	)	$	—		$	(0.1	)

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	$	10.9		$	3.9
Federal tax credit carryforwards		7.9			4.0
State NOL carryforward		3.1			3.4
Valuation allowances for state NOL carryforward		(3.1	)		(3.4	)

The federal carryforward periods expire between 2021 and 2030. The state carryforward periods expire between 2011 and 2023.

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 form:
State income taxes, net of federal income tax benefit		4.1			1.5			5.2
Tax credits recognized, net of federal income tax expense		(1.1	)		(1.1	)		(0.9	)
Resolution of income tax audits and other		(0.2	)		0.5			—
Regulatory differences — utility plant items		(0.7	)		(0.6	)		(1.3	)
Change in unrecognized tax benefits		—			—			0.1
Life insurance policies		(0.2	)		(0.1	)		(0.1	)
Previously recognized Medicare Part D subsidies		1.0			—			—
Other, net		—			(0.1	)		(0.1	)
Effective income tax rate		37.9	%		35.1	%		37.9	%

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

(Thousands of Dollars)	2010			2009			2008
Current federal tax expense	$	3,754		$	16,713		$	20,137
Current state tax expense		1,536			1,236			6,336
Current change in unrecognized tax expense (benefit)		730			(422	)		625
Deferred federal tax expense		19,254			8,412			2,409
Deferred state tax expense (benefit)		2,288			78			(557	)
Deferred change in unrecognized tax expense (benefit)		(707	)		400			(547	)
Deferred tax credits		(121	)		(165	)		—
Deferred investment tax credits		(622	)		(634	)		(629	)
Total income tax expense	$	26,112		$	25,618		$	27,774

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

(Thousands of Dollars)	2010			2009			2008
Deferred tax expense excluding items below	$	20,987		$	8,091		$	3,606
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(222	)		685			(2,252	)
Tax benefit allocated to other comprehensive income		(51	)		(51	)		(49	)
Deferred tax expense	$	20,714		$	8,725		$	1,305

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	$	200,222	$	175,424
Regulatory assets		50,286		50,147
Employee benefits		15,972		15,912
Other		8,676		9,480
Total deferred tax liabilities	$	275,156	$	250,963

Deferred tax assets:
Environmental remediation	$	41,227	$	40,416
Regulatory liabilities		10,077		13,520
Tax credit carryforward		7,870		4,044
Deferred investment tax credits		6,054		4,922
NOL carryforward		4,836		1,980
Other		4,434		6,410
Total deferred tax assets	$	74,498	$	71,292
Net deferred tax liability	$	200,658	$	179,671

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6. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Wisconsin. Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Wisconsin. Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Wisconsin accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy (multiple employer plans). NSP-Wisconsin is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Wisconsin 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-Wisconsin employees.

Xcel Energy, which includes NSP-Wisconsin, offers various benefit plans to its employees. At Dec. 31, 2010, NSP-Wisconsin had 402 bargaining employees covered under a collective-bargaining agreement, which expired at the end of 2010. As of Dec. 31, 2010, contract negotiations with the NSP-Wisconsin bargaining group 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-Wisconsin 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.

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-Wisconsin, 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-Wisconsin’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-Wisconsin base the 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-Wisconsin continually review pension assumptions. In 2011, Xcel Energy will use an investment-return assumption of 7.50 percent.

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The assets are invested in a portfolio according to Xcel Energy’s and NSP-Wisconsin’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 pension asset allocation 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-Wisconsin 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.

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

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	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 year ended Dec. 31, 2010 and 2009:


(Thousands of Dollars)	Jan. 1, 2010		Realized and Unrealized Gains (Losses)			Purchases, Issuances, and 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

			Realized and				Purchases,
			Unrealized Gains				Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		(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

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(Thousands of Dollars)	2010			2009
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-Wisconsin Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	80,360		$	76,573
Prior service cost		5,956			4,920
Total	$	86,316		$	81,493

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	86,316		$	81,493

NSP-Wisconsin accrued benefit liability recorded		30,606			24,006

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.

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.

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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-Wisconsin:
Net periodic pension benefit cost (credit) recognized	$	4,863		$	559		$	(1,041	)

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-Wisconsin, 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.

Xcel Energy, which includes NSP-Wisconsin, also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of operating cash flows.

Defined Contribution Plans

Xcel Energy and NSP-Wisconsin maintain 401(k) and other defined contribution plans that cover substantially all employees. The contributions for NSP-Wisconsin were approximately $1.0 million in 2010 and $0.9 million in 2009 and 2008, respectively.

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Wisconsin, 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 Xcel Energy health care program with no employer subsidy.

In 1993, Xcel Energy and NSP-Wisconsin 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.

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 Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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Xcel Energy and NSP-Wisconsin 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-Wisconsin’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

The following tables present the changes in Level 3 postretirement benefit plan assets for the year 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

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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-Wisconsin Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	10,612		$	10,057
Prior service credit		(126	)		(140	)
Transition obligation		343			514
Total	$	10,829		$	10,431

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	10,829		$	10,431

NSP-Wisconsin accrued benefit liability recorded		19,761			19,927

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.

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


	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-Wisconsin, 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-Wisconsin:
Net periodic postretirement benefit cost recognized	$	1,645		$	2,126		$	2,011

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

Projected Benefit Payments

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
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

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7. 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	$	1,190		$	1,186		$	108
Other non-operating income		459			107			193
Insurance policy (expenses) income		(384	)		(566	)		16
Other income, net	$	1,265		$	727		$	317

8.	Derivative Instruments and Fair Value Measurements

NSP-Wisconsin enters into derivative instruments, including forward contracts, futures, swaps and options, to reduce risk in connection with changes in interest rates and utility commodity prices.

Interest Rate Derivatives — NSP-Wisconsin 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 other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged transactions occur. Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the years ended Dec. 31, 2010 and Dec. 31, 2009 were $0.1 million and $0.1 million, respectively.

Commodity Derivatives — NSP-Wisconsin enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, including the sale of natural gas or the purchase of natural gas for resale.

At Dec. 31, 2010, NSP-Wisconsin had no commodity derivative contracts designated as cash flow hedges. However, as of Dec. 31, 2010, NPS-Wisconsin has entered into derivative instruments that mitigate commodity price risk on behalf of natural gas customers but are not designated as qualifying hedging instruments. Changes in the fair value of these commodity derivative instruments are deferred as a regulatory asset or liability based on commission approved regulatory recovery mechanisms.

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

(Amounts in Thousands) (a)		Dec. 31, 2010				Dec. 31, 2009
MMBtu of natural gas			2,242				2,053

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

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive losses, included as a component of common stockholder’s equity, is detailed in the following table:

(Thousands of Dollars)	2010			2009			2008
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(666	)	$	(742	)	$	(820	)
After-tax net realized losses on derivative transactions reclassified into earnings		76			76			78
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(590	)	$	(666	)	$	(742	)

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

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During the years ended Dec. 31, 2010 and Dec. 31, 2009, changes in the fair value of natural gas commodity derivatives resulted in net losses of 3.4 million and net gains of $0.1 million, respectively, recognized as regulatory assets and liabilities. Natural gas commodity derivatives settlement losses of $1.1 million and $3.4 million were recognized during the years ended Dec. 31, 2010 and Dec. 31, 2009, respectively, and were subject to purchased natural gas cost recovery mechanisms, which reclassify derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate.

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

Certain of NSP-Wisconsin’s derivative instruments are 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-Wisconsin’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Dec. 31, 2010 and Dec. 31, 2009, NSP-Wisconsin 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 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.

Fair value for commodity derivatives is determined based on observable prices for identical or similar forward contracts, or internally prepared option valuation models using observable forward curves and volatilities. 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.

NSP-Wisconsin 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-Wisconsin’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.

The following tables present, for each of these hierarchy Levels, NSP-Wisconsin’s assets and liabilities that are measured at fair value on a recurring basis:


	Dec. 31, 2010
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting (b)			Total
Current derivative liabilities
Natural gas commodity	$	—	$	1,800	$	—	$	1,800	$	(13	)	$	1,787

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	Dec. 31, 2009
	Fair Value
										Fair Value			Counterparty
(Thousands of Dollars)	Level 1			Level 2			Level 3			Total			Netting (b)			Total
Current derivative assets
Natural gas commodity (a)		$	—		$	608		$	—		$	608		$	5		$	613
Current derivative liabilities
Natural gas commodity			—			15			—			15			5			20

(a)

Amounts included in prepayments and other in the consolidated balance sheets.

(b)

The accounting 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-Wisconsin 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.

9.	Financial Instruments

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

	2010				2009
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	119	$	119	$	134	$	134
Long-term debt, including current portion		369,356		416,587		369,343		394,476

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair value of NSP-Wisconsin’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.

Guarantees — NSP-Wisconsin provides a guarantee for payment or performance under a specified agreement. As a result, NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the specified agreement. The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee. The guarantee requires no liability to be recorded, contains no recourse provisions and requires no collateral. On Dec. 31, 2010, NSP-Wisconsin had the following guarantee and exposure related to that guarantee:

(Millions of Dollars)

Guarantee Amount

Current Exposure

Term or

Expiration Date

Triggering

Event

Requiring

Performance

Assets Held

as Collateral

Guarantee of customer loans for the Farm Rewiring Program

1.0

0.5

Continuing

(a)

N/A

(a)	The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Letters of Credit

NSP-Wisconsin may use 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 no letters of credit outstanding.

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10. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — PSCW

Base Rate

2010 Electric Rate Case Reopener — In August 2010, NSP-Wisconsin filed a request with the PSCW to reopen the 2010 rate case and increase retail electric rates for 2011 by $29.1 million, or 5.4 percent, based on a forecast 2011 test year. In January 2011, the PSCW issued its final decision in the case, approving an increase of $21.1 million, or 3.9 percent. The new rates went into effect on Jan. 15, 2011.

Pending and Recently Concluded Regulatory Proceedings — MPSC

2011 Michigan Electric Rate Case — In December 2010, NSP-Wisconsin filed an application with the MPSC to increase base electric rates by $1.1 million, or 9.3 percent based on a forecast 2011 test year. The application is based on a Michigan electric rate base of $22.2 million, a 10.75 percent return on equity and a 52.3 percent common equity ratio. NSP-Wisconsin’s current base electric rates were approved by the MPSC in 1999, based on a 1998 test year. NSP-Wisconsin anticipates resolution of the case in mid-2011.

Pending and Recently Concluded Regulatory Proceedings — FERC

FERC Rate Case for Wholesale Municipal Customers — On April 1, 2010, NSP-Wisconsin filed an application with the FERC seeking changes to the rates, terms and conditions of the firm power sale for resale service agreement provided to its ten wholesale municipal full-requirements customers. In the application NSP-Wisconsin requested to convert from existing cost-based production stated rates to cost-based production formula rates and to set rates that will allow it to collect revenues sufficient to recover significant increases in its costs of services to the customers since rates were last set in 2006.

On May 28, 2010, the FERC issued an order accepting NSP-Wisconsin’s proposed formula rate and related terms and conditions for filing, suspending the rates for one day, allowing the rate formula to become effective July 1, 2010, subject to refund, and establishing hearing and settlement judge procedures. NSP-Wisconsin estimated the new rates would result in an increase in non-fuel revenues of $5.7 million, or 21 percent, for the formula rate year July 1, 2010 through June 30, 2011, as compared to prior stated rates, which were based on a 2006 test year. Settlement judge procedures began in June 2010, and in December 2010, NSP-Wisconsin and the municipal customers reached a settlement in principle. Pursuant to FERC rules, the terms of the settlement are not public at this time. NSP-Wisconsin anticipates a settlement agreement will be filed with FERC in the first quarter of 2011. The settlement agreement must be approved by FERC before it becomes effective.

NSP-Wisconsin estimates the settlement rates will result in an increase in non-fuel revenues of $5.3 million, or 19 percent, for the formula rate year July 1, 2010 through June 30, 2011, a reduction from rates currently in effect subject to refund. Accordingly, NSP-Wisconsin has established a liability of $0.6 million based on the difference between the settlement rates and the rates in effect subject to refund and true-up from July 1, 2010 through Dec. 31, 2010.

As previously noted, NSP-Wisconsin’s two largest wholesale customers, the cities of Medford, Wis. and Rice Lake, Wis., issued notices in December 2010 that they will be canceling their power supply contracts with NSP-Wisconsin and purchasing power from an alternate supplier. Under the notice provisions in their contracts, Medford will terminate service at the end of 2011 and Rice Lake will terminate service at the end of 2012. Until that time, the cities will be served under their existing contracts and the formula rate.

11. Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2010, the estimated cost of capital expenditure programs of NSP-Wisconsin is approximately $150 million in 2011, $170 million in 2012 and $160 million in 2013. NSP-Wisconsin’s capital forecast includes the following major project.

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 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.

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The capital expenditure programs of NSP-Wisconsin 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-Wisconsin’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-Wisconsin has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2011 and 2032. In addition, NSP-Wisconsin may be required to pay additional amounts depending on actual quantities shipped under these agreements. As NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers, NSP-Wisconsin may seek deferred accounting treatment and future rate recovery of increased costs due to an emergency event, if that event causes fuel costs to exceed the amount included in rates on an annual basis by more than 2 percent.

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

(Millions of Dollars)	2010
Coal	$	21.5
Natural gas supply		13.5
Natural gas storage and transportation		100.3

Variable Interest Entities — Effective Jan. 1, 2010, NSP-Wisconsin 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 entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

NSP-Wisconsin has entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. NSP-Wisconsin has determined the low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and NSP-Wisconsin received a larger allocation of the tax credits than the general partners at inception of the arrangements. NSP-Wisconsin determined that it has the power to direct the activities that most significantly impact these entities’ economic performance, and therefore NSP-Wisconsin consolidates these limited partnerships in its consolidated financial statements.

Equity financing for these entities has been provided by NSP-Wisconsin and the general partner of each limited partnership, and NSP-Wisconsin’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by NSP-Wisconsin. Mortgage-backed debt comprised the majority of the financing at inception of each limited partnership and is to be paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to NSP-Wisconsin or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of NSP-Wisconsin or its subsidiaries.

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Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following:


(Thousands of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Current assets	$	228	$	208
Property, plant and equipment, net		2,891		3,030
Other noncurrent assets		89		82
Total assets	$	3,208	$	3,320

Current liabilities	$	1,612	$	1,476
Mortgages and other long-term debt payable		486		684
Other noncurrent liabilities		43		40
Total liabilities	$	2,141	$	2,200

Leases — NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases. Rental expense under operating lease obligations was approximately $1.4 million, $1.9 million and $2.1 million for 2010, 2009 and 2008, respectively. The majority of rental expense is for one-year renewable leases.

Future commitments under operating leases are:


(Millions of Dollars)
2011	$	1.4
2012		1.2
2013		1.1
2014		1.1
2015		1.1
2016 and thereafter		6.6
Total	$	12.5

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

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.

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Environmental Contingencies

NSP-Wisconsin has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Wisconsin 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-Wisconsin, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, NSP-Wisconsin 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-Wisconsin must pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin or other parties have caused environmental contamination. Environmental contingencies could arise from various situations including sites of former MGPs operated by NSP-Wisconsin, its predecessors, or other entities; and third party sites, such as landfills, for which NSP-Wisconsin 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 $102.8 million and $100.8 million, respectively, of which $5.1 million and $5.7 million, respectively, was considered to be a current liability.

MGP Sites

Ashland MGP Site — NSP-Wisconsin has been named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (Ashland site) includes property owned by NSP-Wisconsin, which was previously an MGP facility and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill; and an area of Lake Superior’s Chequamegon Bay adjoining the park.

In 2002, the Ashland site was placed on the National Priorities List. In 2009, the EPA issued its proposed remedial action plan (PRAP). The EPA issued its Record of Decision (ROD) in September 2010, which documents the remedy that the EPA has selected for the cleanup of the site. The EPA has estimated the cost for its selected cleanup is between $83 million and $97 million. The EPA’s cost estimate is expected to be within plus 50 percent to minus 30 percent of the actual project costs. It is anticipated that the EPA will issue special notice letters to several PRPs, including NSP-Wisconsin in 2011, and in those letters, the EPA will invite the PRPs to participate in negotiations with the EPA to conduct or pay for all, or a portion, of the future cleanup work at the site.

NSP-Wisconsin’s potential liability, the actual cost of remediating the Ashland site and the time frame over which the amounts may be paid out are not determinable until after the EPA issues special notice letters and engages in negotiations with the PRPs at the site. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. NSP-Wisconsin has recorded a liability of $97.5 million based upon potential remediation and design costs, together with estimated outside legal and consultant costs.

NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.

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In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers.

In addition to potential liability for remediation, NSP-Wisconsin may also have potential liability for natural resource damages at the Ashland site. NSP-Wisconsin has recorded an estimate of its potential liability based upon its best estimate of potential exposure.

Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Wisconsin’s removal costs for asbestos are expected to be immaterial; therefore, no ARO was recorded. 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 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 Wisconsin. 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 Wisconsin for annual SO2 and NOx emissions. NSP-Wisconsin is analyzing the proposed rule to determine whether emission reductions are needed from facilities. Until CATR becomes final, NSP-Wisconsin will continue activities to support CAIR compliance.

The NOx allowance cost in 2010 for NSP-Wisconsin was $0.1 million. NSP-Wisconsin believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

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-Wisconsin 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.

Wisconsin Mercury Rule — In December 2008, the Wisconsin mercury reduction rule took effect, which impacts NSP-Wisconsin’s Bay Front plant. The rule applies to coal-fired utility boilers and requires that small coal-fired utility boilers, which include all three boilers at the Bay Front plant, must perform a top-down BACT analysis for mercury by June 30, 2011, and limit mercury emissions to a level that is determined by the WDNR to be BACT by Jan. 1, 2015.

NSP-Wisconsin had proposed a gasifier project for boiler 5 at the Bay Front plant. In November 2010, NSP-Wisconsin notified the PSCW that it will not be proceeding with the project due to a significant increase in the estimated costs, declining costs of generation options and considerable regulatory uncertainty at the state and federal level. As long as boiler 5 continues to burn coal, it will be subject to this rule and must perform the analysis under the Wisconsin mercury rule. In addition, if the industrial boiler MACT is revised prior to 2015, boilers 1 and 2 will no longer be subject to the Wisconsin mercury reduction rule, and will need to comply with the Boiler MACT. As such, any cost estimates to comply with the Wisconsin mercury reduction rule are premature at this time.

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Federal Clean Water Act — 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.

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-Wisconsin 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 — NSP-Wisconsin 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.

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Wisconsin’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						to Prior			Balance
(Thousands of Dollars)		Jan. 1, 2010		Accretion			Estimates			Dec. 31, 2010 (a)
Electric plant
Electric transmission and distribution		$	26		$	2		$	39		$	67
Natural gas plant
Gas transmission and distribution			60			3			—			63
Total liability (b)		$	86		$	5		$	39		$	130

NSP-Wisconsin revised electric transmission and distribution AROs due to revised estimates and end of life dates.


	Beginning						Revisions				Ending
	Balance						to Prior				Balance
(Thousands of Dollars)		Jan. 1, 2009		Accretion			Estimates				Dec. 31, 2009 (a)
Electric plant
Electric transmission and distribution		$	29		$	2		$	(5	)		$	26
Natural gas plant
Gas transmission and distribution			56			4			—				60
Total liability (b)		$	85		$	6		$	(5	)		$	86

(a)	There were no ARO liabilities recorded or liabilities settled during the 12 months ended Dec. 31, 2010 or Dec. 31, 2009.

(b)	Included in other liabilities balance of $8,143 and $3,884 at Dec. 31, 2010 and 2009, respectively, in the consolidated balance sheets.

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NSP-Wisconsin revised electric transmission and distribution AROs due to revised estimates and end of life dates.

Removal Costs — NSP-Wisconsin 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-Wisconsin 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 Dec. 31, 2009 were $107 million and $102 million, respectively.

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-Wisconsin’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-Wisconsin, 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-Wisconsin, 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, rendering the district court’s dismissal the final determination.

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-Wisconsin, 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.

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Employment, Tort and Commercial Litigation

Robarge vs. NSP-Wisconsin — Plaintiff in this purported class action, served in late 2009 and venued in County Circuit Court in Eau Claire, Wis., alleges that NSP-Wisconsin has engaged in unfair and improper refund practices regarding the cost of service extensions and seeks certification of a class of those similarly situated. Plaintiff claims entitlement to actual damages in an amount, as yet undetermined, punitive damages, injunctive relief, and fees and costs. NSP-Wisconsin filed a motion for summary judgment in April 2010 and filed its opposition to plaintiff’s motion for class certification in July 2010. In January 2011, the court issued an order denying plaintiff’s motion for class certification and granting NSP-Wisconsin’s motion for summary judgment.

12. Regulatory Assets and Liabilities

NSP-Wisconsin’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-Wisconsin no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in its consolidated statements of income.

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

	See	Remaining
(Thousands of Dollars)	Note	Amortization Period	Dec. 31, 2010						Dec. 31, 2009
			Current		Noncurrent			Current			Noncurrent
Regulatory Assets
Environmental remediation costs	11	Various	$	543		$	97,466		$	543		$	94,511
Pension and employee benefit obligations (a)	6	Various		6,234			90,511			4,464			86,899
Losses on reacquired debt	1	Term of related debt		1,048			8,181			1,048			9,229
AFUDC recorded in plant (b)	1	Plant lives		—			9,887			—			9,143
State commission adjustments (b)	1	Plant lives		—			4,115			—			3,770
Deferred income tax adjustment	1	Typically plant lives		—			3,665			—			2,298
Other		Various		6,259			577			5,286			3,511
Total regulatory assets			$	14,084		$	214,402		$	11,341		$	209,361

Regulatory Liabilities
Deferred electric and gas production costs	1		$	3,514		$	—		$	18,493		$	—
Plant removal costs	11			—			106,569			—			102,111
Investment tax credit deferrals	1			—			10,106			—			8,217
Other				6,863			643			1,218			1,582
Total regulatory liabilities			$	10,377		$	117,318		$	19,711		$	111,910

(a) Includes the non-qualified pension plan.

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

13. Segments and Related Information

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

●	NSP-Wisconsin’s regulated electric utility segment generates, transmits and distributes electricity in Wisconsin and Michigan. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities primarily in Wisconsin.

●	NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas in portions of Wisconsin and Michigan.

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●	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 investments in rental housing projects that qualify for low-income housing tax credits.

Operating results from the regulated electric utility and regulated natural gas serve as the primary basis for the chief operating decision maker to evaluate the dual performance of NSP-Wisconsin. 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-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin 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	$	708,179	$	118,076	$	1,036		$	—		$	827,291
Intersegment revenues		360		1,122		—			(1,482	)		—
Total revenues	$	708,539	$	119,198	$	1,036		$	(1,482	)	$	827,291

Depreciation and amortization	$	54,414	$	9,037	$	218		$	—		$	63,669
Interest charges and financing cost		20,738		2,597		143			—			23,478
Income tax expense (benefit)		24,819		1,836		(543	)		—			26,112
Net income		37,773		3,325		1,651			—			42,749

2009
Operating revenues from external customers	$	671,703	$	131,555	$	893		$	—		$	804,151
Intersegment revenues		136		1,054		—			(1,190	)		—
Total revenues	$	671,839	$	132,609	$	893		$	(1,190	)	$	804,151

Depreciation and amortization	$	52,622	$	8,959	$	176		$	—		$	61,757
Interest charges and financing cost		21,082		2,715		167			—			23,964
Income tax expense (benefit)		25,877		3,075		(3,334	)		—			25,618
Net income		40,281		3,932		3,150			—			47,363

2008
Operating revenues from external customers	$	665,375	$	179,434	$	910		$	—		$	845,719
Intersegment revenues		181		1,829		—			(2,010	)		—
Total revenues	$	665,556	$	181,263	$	910		$	(2,010	)	$	845,719

Depreciation and amortization	$	49,727	$	8,432	$	176		$	—		$	58,335
Interest charges and financing cost		20,611		2,796		1,181			—			24,588
Income tax expense (benefit)		24,287		4,390		(903	)		—			27,774
Net income (loss)		39,305		6,502		(286	)		—			45,521

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14. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including NSP-Wisconsin. 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.

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	$	116,312	$	109,251	$	106,363
Operating expenses:
Purchased power		377,518		353,248		357,946
Transmission expense		38,558		35,775		32,197
Natural gas purchased for resale		163		309		312
Other operating expenses - paid to Xcel Energy Services Inc.		52,826		48,533		45,819
Interest expense		56		66		1,064

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


	2010				2009
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	—	$	26,864	$	—	$	31,243
PSCo		—		164		—		30
SPS		2		—		—		29
Other subsidiaries of Xcel Energy		1		9,292		20,448		7,420
	$	3	$	36,320	$	20,448	$	38,722

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-Wisconsin had notes payable outstanding to NSP-Minnesota in the amount of $37.0 million and $15.5 million, respectively.

Clearwater Investments Inc., an NSP-Wisconsin subsidiary, also had notes payable outstanding of $0.6 million as of Dec. 31, 2010 and 2009 to Xcel Energy.

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15. Summarized Quarterly Financial Data (Unaudited)

Due to the seasonality of NSP-Wisconsin’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	$	224,769		$	179,597		$	211,068		$	211,857
Operating income		28,867			8,994			33,131			17,829
Net income		13,544			2,679			17,624			8,902


	Quarter Ended
(Thousands of Dollars)	March 31, 2009		June 30, 2009			Sept. 30, 2009			Dec. 31, 2009
Operating revenues	$	248,854		$	171,186		$	182,265		$	201,846
Operating income		41,116			10,656			25,954			16,855
Net income		21,721			3,476			13,623			8,543

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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-Wisconsin on accounting principles or practices, financial statement disclosures or audit scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Wisconsin 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-Wisconsin’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-Wisconsin’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Wisconsin’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-Wisconsin’s internal control over financial reporting. NSP-Wisconsin maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Wisconsin 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-Wisconsin conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Wisconsin 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-Wisconsin’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by NSP-Wisconsin’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit NSP-Wisconsin to provide only management’s report in this annual report.

Item 9B — Other Information

None

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been 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 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

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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*		Amended and restated articles of incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) Jan. 21, 2004).
3.02*		By-Laws of NSP-Wisconsin as amended June 3, 2008 (Exhibit 3.02 to Form 10-Q (file no. 001-03140) Aug. 4, 2008).
4.01*		Supplemental and Restated Trust Indenture dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust company, providing for the issuance of First Mortgage Bonds (Exhibit 4.01K to Registration Statement 33-39831).
4.02*		Supplemental Trust Indenture dated April 1, 1991 (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
4.03*		Supplemental Trust Indenture dated Dec. 1, 1996 (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
4.04*		Trust Indenture dated Sept. 1, 2000, between NSP-Wisconsin and Firstar Bank, NA as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
4.05*		Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and US Bank NA, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.06*		Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S.Bank NA, as successor Trustee, creating $200,000,000 principal amount of 6.375 percent First Mortgage Bonds, Series due Sept. 1, 2038 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Sept. 3, 2008 (file no. 001-03140)).
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 as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

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10.09*+		Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+		Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+		Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.14*+		Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.15*+		Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*		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).
10.17*+		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).
10.18*+		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).
10.19*+		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).
10.20*+		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).
10.21*+		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).
10.22*+		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).
10.23*+		Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.24*+		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).
10.25*+		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.

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SCHEDULE II

NSP-WISCONSIN 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	$	4,709	$	3,294	$	1,207	$	4,948	$	4,262
2009		4,658		4,505		1,050		5,504	$	4,709
2008		2,830		4,784		1,135		4,091		4,658

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off or transferred.

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SIGNATURES

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

	NORTHERN STATES POWER COMPANY

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

February 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 on February 28, 2011.

/S/ MICHAEL L. SWENSON		/S/ RICHARD C. KELLY
Michael L. Swenson		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-Wisconsin has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

Attached files

NORTHERN STATES POWER CO /WI/ Reports

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