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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

Washington, D.C.  20549
For the fiscal year ended December 31, 2010
Commission File Number: 001-03140
Northern States Power Company
 (Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization)
(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.
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).



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.
Xcel Energy Subsidiaries and Affiliates (current and former)
New Century Energies, Inc.
Northern States Power Company, a Minnesota corporation
Northern States Power Company, a Wisconsin corporation
Public Service Company of Colorado, a Colorado corporation
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
United States Environmental Protection Agency
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.
Internal Revenue Service
Michigan Public Service Commission.  The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.
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.
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.
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.
Nuclear Regulatory Commission.  The federal agency that regulates the operation of nuclear power plants.
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.
Securities and Exchange Commission
Wisconsin Department of Natural Resources
Electric, Purchased Gas and Resource Adjustment Clauses
Demand side management.  Energy conservation, weatherization and other programs to conserve or manage energy use by customers.
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.
Other Terms and Abbreviations
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.
Accumulated Postretirement Benefit Obligation
Aggregator of Retail Customers
Asset retirement obligation.  Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
FASB Accounting Standards Codification
Best Available Control Technology
Buffalo Ridge Incremental Generation Outlet
Carbon dioxide
Clean Air Act
Clean Air Interstate Rule
Clean Air Mercury Rule
An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
Clean Air Transport Rule
Critical Infrastructure Protection Standards
FASB Accounting Standards Codification
Clean Water Act
Construction work in progress
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
The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
Effective tax rate
Financial Accounting Standards Board
Generally accepted accounting principles
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).
Greenhouse gas
Liquefied natural gas.  Natural gas that has been converted to a liquid.
Maximum Achievable Control Technology
The process whereby an asset or liability is recognized at fair value.
Manufactured gas plant
Midwest Independent Transmission System Operator, Inc.
Moody’s Investor Services Inc.
Midwest Reliability Organization
Multi-Value Project

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.
Notice of proposed rulemaking
Nitrogen oxide
All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
Operating and maintenance
Other comprehensive income
Polychlorinated biphenyl
PJM Interconnection, LLC
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.
Regional Expansion Criteria Benefits
Request for proposal
Return on equity
Right of first refusal
Renewable Portfolio Standard.  A regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
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.
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.
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.
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.
Kilovolts (one KV equals one thousand volts)
Kilowatts (one KW equals one thousand watts)
Kilowatt hours
Thousand cubic feet
One million Btus
Megawatts (one MW equals one thousand KW)
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.
A measure of power production or usage.

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.
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.
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.
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.
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)
  $ 120  
2014 and thereafter
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.
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)
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.
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.
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.
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  
Natural Gas
Fuel Cost
  $ 1.89       51 %   $ 0.83       42 %   $ 6.29       7 %   $ 1.73  
    1.78       57       0.70       39       7.36       4       1.61  
    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.
Coal — The NSP System normally maintains approximately 40 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2010 and 2009 were approximately 39 and 43 days usage, respectively.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana.  Estimated coal requirements at NSP-Minnesota’s and NSP-Wisconsin’s major coal-fired generating plants were approximately 9.9 and 10.2 million tons per year at Dec. 31, 2010 and 2009, respectively.
NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 85 percent of their coal requirements in 2011, 75 percent of their coal requirements in 2012 and 31 percent of their coal requirements in 2013.  Any remaining requirements will be filled through a RFP process or through over-the-counter transactions.
NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements through 2013.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Nuclear — To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication.  The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium, conversion and enrichment with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2012, approximately 66 percent of the requirements for 2013 through 2017, and approximately 38 percent of the requirements for 2018 through 2025.  Contracts for additional uranium concentrate supplies are currently being negotiated that are expected to provide a portion of the remaining open requirements through 2025.
Current contracts for conversion services cover 100 percent of the requirements through 2011, approximately 78 percent of the requirements from 2012 through 2016, and approximately 30 percent of the requirements for 2017 through 2025.  Contracts for additional conversion services are being negotiated to provide a portion of remaining open requirements for 2012 and beyond.
Current enrichment services contracts cover 100 percent of 2011 through 2016 requirements, and approximately 54 percent of the requirements for 2017 through 2025.  Contracts for additional enrichment services are being negotiated to provide a portion of the remaining open requirements for 2017 and beyond.
Fabrication services for Monticello are covered through 2014.  A contract for fuel fabrication services for Monticello for 2015 and beyond is currently being negotiated.  Prairie Island’s fuel fabrication is 100 percent committed to 2015.
NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants.  Some exposure to spot market price volatility will remain, due to index-based pricing structures contained in some of the supply contracts.
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.
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.
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.

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.

Year Ended Dec. 31,
Electric sales (Millions of KWh)
    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
    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  
    10       10       10  
Total customers
    249,815       248,944       248,459  
Electric revenues (Thousands of Dollars)
  $ 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  
    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  
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.
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.
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.
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.
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:
  $ 5.46  
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.
Year Ended Dec. 31,
Natural gas deliveries (Thousands of MMBtu)
    6,278       6,825       7,155  
Commercial and industrial
    8,063       8,656       8,921  
Total retail
    14,341       15,481       16,076  
    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
    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)
  $ 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  
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.
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.
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.

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.
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.
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.

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.
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.

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.

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.
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.
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
Capability (MW)
Bay Front-Ashland, Wis., 3 Units
 Coal/Wood/Natural Gas
    1948-1956       56  
French Island-La Crosse, Wis., 2 Units
  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  
Various locations, 63 Units
(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
161 KV
115 KV
Less than 115 KV
NSP-Wisconsin had 204 electric utility transmission and distribution substations at Dec. 31, 2010.

Natural gas utility mains at Dec. 31, 2010:
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.
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)
First quarter
  $ 48,774     $ 8,554  
Second quarter
    8,119       8,611  
Third quarter
    8,453       8,511  
Fourth quarter
    8,441       8,522  
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).
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.

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)
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
Estimated impact of weather
Sales mix and demand revenue
    (6 )
Other, net
    (1 )
Total increase in electric revenue
  $ 36  
Electric Margin
(Millions of Dollars)
2010 vs. 2009
Retail rate increases
  $ 25  
Estimated impact of weather
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)
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
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 )
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
Higher plant generation costs
Higher contract labor costs
Higher labor costs
Higher insurance costs
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.
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.
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.
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.

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.
Michael L. Swenson
David M. Sparby
President and Chief Executive Officer
Vice President and Chief Financial Officer
February 28, 2011
February 28, 2011

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.
Minneapolis, Minnesota
February 28, 2011

(amounts in thousands of dollars)
Year Ended Dec. 31
Operating revenues
  $ 708,179     $ 671,703     $ 665,375  
Natural gas
    118,076       131,555       179,434  
    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

(amounts in thousands of dollars)
Year Ended Dec. 31
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 )
    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
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

(amounts in thousands of dollars)
Dec. 31
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  
    26,616       28,443  
Regulatory assets
    14,084       11,341  
Prepaid taxes
    21,097       26,646  
Deferred income taxes
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  
    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  
    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  
    8,142       3,884  
Total deferred credits and other liabilities
    500,047       469,557  
Commitments and contingent liabilities
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 stockholders equity
    502,678       493,074  
Total liabilities and equity
  $ 1,526,528     $ 1,474,829  
See Notes to Consolidated Financial Statements

(amounts in thousands of dollars, except share data)
Common Stock
Paid In
Par Value
Income (Loss)
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
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
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
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
(amounts in thousands of dollars)
Dec. 31
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%
Sept. 1, 2038, 6.375%
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% (a)
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%
Unamortized discount
Less current maturities
Total long-term debt
Common Stockholder’s Equity
Common Stock — authorized 1,000,000 shares of $100 par value; outstanding 933,300 shares in 2010 and 2009
Additional paid in capital
Retained earnings
Accumulated other comprehensive loss
Total common stockholder’s equity
(a) Resource recovery financing
See 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.