UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2008

Or

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

Commission file number 001-03140

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Wisconsin		39-0508315
State or other jurisdiction of		(I.R.S. Employer
Incorporation or organization		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. S 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 Feb. 27, 2009, 933,000 shares of common stock, par value $100 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2009 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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

Table of Contents

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

*Xcel Energy Subsidiaries and Affiliates*
NSP-Minnesota		Northern States Power Co., a Minnesota corporation
NSP-Wisconsin		Northern States Power Co., a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
SPS		Southwestern Public Service Co., a New Mexico corporation
utility subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy		Xcel Energy Inc., a Minnesota corporation

*Federal and State Regulatory Agencies*
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas, the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates and accounting requirements for utility holding companies, service companies and public utilities.
IRS		Internal Revenue Service
MPSC		Michigan Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.
MPUC		Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NERC		North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the U.S. Federal Energy Regulatory Commission and government authorities in Canada, to develop and enforce reliability standards.
NRC		Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
PSCW		Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.
WDNR		Wisconsin Department of Natural Resources
SEC		Securities and Exchange Commission

*Other Terms and Abbreviations*
AFDC		Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ		Administrative law judge. A judge presiding over regulatory proceedings.
ARO		Asset Retirement Obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
CO2		Carbon dioxide
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CapX 2020		An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
COLI		Corporate-owned life insurance
decommissioning		The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.

Table of Contents

derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	·	An underlying and a notional amount or payment provision or both,
	·	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and
	·	Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
FASB	Financial Accounting Standards Board
FTRs	Financial Transmission Rights. Used to hedge the costs associated with transmission congestion.
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
GHG	Greenhouse Gas
LNG	Liquefied natural gas. Natural gas that has been converted to a liquid.
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services Inc.
native load	The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas	A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
NOx	Nitrogen oxide
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
PUHCA	Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies.
QF	Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
rate base	The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
ROE	Return on equity
RTO	Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS	Statement of Financial Accounting Standards
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
TEMT	Transmission and Energy Markets Tariff of MISO. The tariff requires RTOs such as the MISO to provide real-time energy imbalance services and a market-based mechanism for congestion management.
unbilled revenues	Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying	A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission	An electric service wherein high voltage transmission facilities of one utility system

Table of Contents

		are used to transmit power generated within or purchased from another system.
*Measurements*
Btu		British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
KV		Kilovolts (one KV equals one thousand volts)
KW		Kilowatts (one KW equals one thousand watts)
Kwh		Kilowatt hours
Mcf		Thousand cubic feet
MMBtu		One million Btus
MW		Megawatts (one MW equals one thousand KW)
Watt		A measure of power production or usage.

COMPANY OVERVIEW

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility 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 2008. 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 248,000 customers and natural gas utility service to approximately 104,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2008. Generally, NSP-Wisconsin’s earnings range from 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 and related financial information for fiscal 2008, 2007 and 2006 are set forth in Note 15 to the accompanying consolidated financial statements.

NSP-Wisconsin focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers. NSP-Wisconsin files periodic rate cases or establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investment and recover costs of operations.

ELECTRIC UTILITY OPERATIONS

Overview

Climate Change and Clean Energy — Like most other utilities, NSP-Wisconsin is subject to a significant array of environmental regulations focused on many different aspects of its operations. 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. NSP-Wisconsin’s electric generating facilities are likely to be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. Numerous states have proposed or implemented clean energy policies, such as renewable energy portfolio standards or demand side management (DSM) programs, in part designed to reduce the emissions of GHGs. Congress and federal policy makers are considering climate change legislation and a variety of national climate change policies. NSP-Wisconsin is advocating with state and federal policy makers for climate change and clean energy policies that will result in significant long-term reduction in GHG emissions, develop low-emitting technologies and secure, cost-effective energy supplies for our customers and our nation.

Table of Contents

While NSP-Wisconsin is not currently subject to state or federal limits on its GHG emissions, we have undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions. These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects. Although the impact of climate change policy on NSP-Wisconsin will depend on the specifics of state and federal policies and legislation, we believe that, based on prior state commission practice, we would be granted the authority to recover the cost of these initiatives through rates.

Utility Restructuring and Retail Competition — The FERC has continued with its efforts to promote more competitive wholesale markets through open-access transmission and other means. As a consequence, NSP-Wisconsin and its wholesale customers can purchase 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. In 2008, the FERC approved a MISO proposal to begin operation of a regional Ancillary Services Market (ASM) in January 2009. NSP-Wisconsin supports the continued development of wholesale competition and non-discriminatory wholesale open access transmission services. 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.

The retail electric business faces competition as 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 or steam/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.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion).

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 — On Feb. 23, 2009, NSP-Wisconsin filed an application for a certificate of authority to install biomass gasification technology at the Bay Front Power Plant in Ashland, Wis. Currently, two of the three boilers at Bay Front use biomass as their primary fuel to generate electricity. The proposed project will convert the existing coal-fired unit to biomass gasification technology allowing the plant to use 100 percent biomass in all three boilers. The project, estimated at $58 million, will require 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. The total generation output of the plant is not expected to change significantly as a result of the project. However, the project will improve the environmental performance of the plant and contribute towards state renewable energy standards in the region. Following all state regulatory approvals, engineering and design work is expected to begin in 2010, and the unit could be operational by late 2012. When complete, the Bay Front Power Plant will be the largest biomass-fueled power plant in the Midwest and one of the largest in the nation.

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 those costs that were included in the latest retail electric rates. If the comparison results in a difference of 2 percent above or below base rates, 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 an FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

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, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Table of Contents

Wisconsin Renewable Portfolio Standard (RPS) — The Wisconsin legislature passed a RPS that requires 10 percent of electric sales statewide 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 12.85 percent because its baseline percentage was 6.85 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. Costs associated with complying with the standard are recoverable through general rate cases and the fuel cost recovery mechanism described above.

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2009, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2006	2007	2008	2009 Forecast

NSP System	9,859	9,427	8,697	9,662

The peak demand for the NSP System typically occurs in the summer. The 2008 uninterrupted system peak demand for the NSP System occurred on July 29, 2008.

Energy Sources and Related Transmission Initiatives

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

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

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.

NSP System Resource Plan — In December 2007, NSP-Minnesota filed its 2007 resource plan with the MPUC. The plan incorporates the actions needed to comply with expansive new legislation regarding GHG emissions control, renewable energy procurement, and DSM adopted by the 2007 Minnesota legislature. Due to the expansion of wind generation procurement and DSM obligations, the plan indicates that the type of incremental resources has changed from prior plans. Key highlights of the plan include:

· Additional 2,600 MW of wind generation resources to comply with our RES of 30 percent renewable energy by 2020.

· Increases in DSM of approximately 30 percent energy savings and 50 percent demand savings.

· Seek license renewals for Prairie Island’s two units through 2033 and 2034, respectively, and expand capacity at Prairie Island by 160 MW and Monticello by 71 MW.

· Request approval to make environmental and capacity upgrades at Sherburne County (Sherco). The environmental upgrades would result in a significant reduction in overall SO2, NOx and mercury emissions from the facility.

· Negotiate and seek approval of purchases from Manitoba Hydro Electric Board (Manitoba Hydro) for 375 MW of intermediate and 350 MW of peaking resources beginning in 2015.

· Incremental peaking and intermediate generation needs of 2,300 MW.

· Carbon emission reductions of 22 percent below 2005 levels by 2020.

Table of Contents

In June 2008, intervenors filed comments on this plan. The Minnesota Office of Energy Security (OES) recommended approval, subject to further expansion of DSM goals. Environmental intervenors recommended expanded DSM goals and expressed concerns regarding carbon management with the proposed expansion of certain coal resources. Excelsior Energy recommended inclusion of its proposed project in the plan. The Prairie Island Community expressed health and safety concerns regarding nuclear resources. The Minnesota Chamber of Commerce expressed interest in cost and rate management. NSP-Minnesota filed reply comments in September 2008 providing updated information, including a revised forecast. In light of recent significant changes in the national economy, lower forecast of energy consumption, and new information concerning an emerging technology that may be more cost effective, NSP-Minnesota filed a request with the MPUC to withdraw its Sherco 70 MW capacity expansion and environmental upgrade proposal. The MPUC granted the withdrawal request on Dec. 9, 2008.

Fuel Supply and Costs

For the NSP System, 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 during such years.

													Weighted
NSP System	Coal*				Nuclear				Natural Gas				Average Fuel
Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Cost

2008	$	1.73	58	%	$	0.56	39	%	$	10.09	3	%	$	1.55
2007	1.56		57		0.51		38		7.60		4		1.47
2006	1.12		59		0.46		38		7.28		3		1.08

* Includes refuse-derived fuel and wood

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

Fuel Sources

Coal — The NSP System normally maintains approximately 39 days of coal inventory at each plant site. Coal inventory levels, however, vary widely among plants. Coal supply inventories at Dec. 31, 2008 and 2007, were approximately 49 and 47 days usage, based on the maximum burn rate for all of NSP-Minnesota’s coal-fired plants. 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 and NSP-Wisconsin’s major coal-fired generating plants were approximately 11.0 and 12.4 million tons per year at Dec. 31, 2008 and 2007.

NSP-Wisconsin and NSP-Minnesota have contracted for coal supplies to provide for delivery of 100 percent of their coal requirements in 2009, 65 percent of their coal requirements in 2010 and 36 percent of their coal requirements in 2011. Any remaining requirements will be filled through a request for proposal (RFP) process according to the fuel supply operations procurement strategy.

NSP-Wisconsin and NSP-Minnesota have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2009, 100 percent of their coal requirements in 2010 and 28 percent of their coal requirements 2011. Coal delivery may be subject to short-term interruptions or reductions due to operation of 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 geographical diversification to minimize potential impacts caused by supply interruptions that may be exacerbated by geo-political issues and supply/demand imbalance.

· Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2009, approximately 68 percent of the requirements for 2010, 80 percent of the requirements for 2011 through 2013, 47 percent of the requirements for 2014 through 2017, with no arrangements for 2018 and beyond. Contracts for additional uranium concentrate supplies are currently in various stages of negotiations that are expected to provide a portion of the remaining open requirements through 2012.

Table of Contents

· Current contracts for conversion services cover 100 percent of the requirements through 2011 and approximately 56 percent of the requirements from 2012 through 2015, with no arrangements for 2016 and beyond.

· Current enrichment services contracts cover 100 percent of 2009 through 2012 requirements and approximately 60 percent of 2013 requirements. A contract for additional enrichment services is being negotiated to provide the remainder of coverage for open requirements in 2013. There is currently no coverage for 2014 and beyond. Offers for enrichment services for supply contracts for 2014 and beyond are being reviewed.

· The fuel fabrication contract for Monticello was extended during 2007 to cover one additional reload in 2011. Request for proposals from the fuel fabrication vendors for additional supply for Monticello were distributed. Offers from fuel fabrication vendors are being reviewed with plans to enter into a contract with one of the vendors in 2009. Prairie Island’s fuel fabrication is 100 percent committed to at least 2015.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium are currently being negotiated that would provide additional supply requirements through 2012. Some exposure to price volatility will remain, due to index-based pricing structures on the 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 2009 to 2028. 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, 2008, NSP-Minnesota’s commitments related to supply contracts were $89 million and commitments related to transportation and storage contracts were approximately $652 million. The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Wisconsin. State and local agencies have jurisdiction over many of NSP-Wisconsin’s activities, including regulation of retail rates and environmental matters.

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

· Adopting regulations requiring NERC to establish mandatory electric reliability standards; and

· Certifying approximately 120 NERC reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance.

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

Electric Reliability Standards Matters — The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System. On Sept. 18, 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. The initial transmission line outage appears to have occurred on the NSP-Minnesota transmission system due to a failure of a 345 KV conductor during severe weather, and approximately 6,000 NSP-Wisconsin customers temporarily lost power. The Midwest Reliability Organization (MRO), the NERC regional entity responsible for oversight of electric system reliability in the upper Midwest, including the NSP System, initiated an independent incident analysis. In addition, NERC initiated a compliance investigation to determine if violations of mandatory NERC reliability standards contributed to the event. Xcel Energy is cooperating with the MRO incident analysis and NERC compliance investigation.

Table of Contents

In April 2008, a self-report was filed with MRO indicating that certain tests of generation station batteries had not been completed in accordance with Xcel Energy’s adopted maintenance plan for generation station relays and batteries. Xcel Energy has received preliminary information from the MRO indicating that penalties are likely to be assessed against NSP-Minnesota and NSP-Wisconsin in conjunction with this self-report, though the amount of those penalties is not expected to be material.

In June 2008, PSCo was subject to an audit of its compliance with NERC and regional reliability standards by Western Electricity Coordinating Council, the NERC regional entity for the PSCo system. In response to information identified during the audit, Xcel Energy conducted a comprehensive review of the maintenance records for all relay devices on the NSP-Minnesota and NSP-Wisconsin transmission systems. That review found NSP-Minnesota and NSP-Wisconsin did not have documentation demonstrating that all relay devices on those systems had been maintained on the schedule in Xcel Energy’s adopted maintenance plan. In June 2008, the NSP System filed a self-report regarding the maintenance plan violations with the MRO. The NSP System supplemented the self-report on Feb. 17, 2009.

In September 2008, as a result of a review of Xcel Energy’s procedures implementing certain NERC critical infrastructure protection standards applicable to control centers effective July 1, 2008, the NSP System filed a self-report with the MRO disclosing certain deficiencies in requirements applicable to access to critical infrastructure assets for the period July to September 2008. The NSP System filed a mitigation plan with the MRO within 30 days of the self-report discussing how the deficiencies were corrected. The MRO notified the NSP System it would not impose a financial penalty related to the self-report.

Xcel Energy is uncertain if the NERC investigation regarding the Sept. 18, 2008 NSP System event or the self-reports of reliability standards violations will result in financial penalties being imposed on NSP-Minnesota and NSP-Wisconsin. If so, the penalties are not expected to be material.

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 over their electric transmission assets and 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.

In February 2007, the FERC issued final rules (Order No. 890) adopting revisions to its open access transmission service rules. In December 2007, the FERC issued an order on rehearing (Order No. 890-A) making certain modifications to Order No. 890, effective in March 2008. In June 2008, the FERC issued a further order on rehearing (Order No. 890-B) making certain additional modifications to Order Nos. 890 and 890-A effective in September 2008. Xcel Energy submitted its compliance filing to Order No. 890-B in September 2009. The various compliance filings are pending FERC action.

Centralized Regional Wholesale Markets — The FERC rules allow RTOs to operate centralized regional wholesale energy markets. In April 2005, MISO began operation of a “Day 2” regional day-ahead and real time wholesale energy market. MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTRs. The Day 2 market is designed to provide more efficient generation dispatch over the 15 state MISO region, including the NSP System. In 2007, SPP began operation of an Energy Imbalance Service (EIS) market, which will provide a more limited wholesale energy balancing market for the region that includes the SPS system.

In September 2007, MISO filed for FERC approval to establish a centralized regional wholesale ASM in 2008. The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market. In February 2008, the FERC issued an order conditionally approving the ASM tariff, but requiring certain changes. In December 2008, the FERC issued orders approving the MISO filings necessary for MISO to start the ASM. MISO began ASM operations in January 2009. To date, the ASM has generally functioned as anticipated.

In December 2007, MISO filed proposed changes to the TEMT (called Module E) to establish a long-term resource adequacy proposal. The proposal contains mandatory requirements for any market participant serving load in the MISO region, including the NSP System, to have and maintain access to sufficient resources to meet adequacy standards. The resources used to meet a resource adequacy requirement may include self-generation capacity, firm purchased power and demand response capability.

Under the Module E proposal, MISO will establish a Planning Reserve Margin for each Load-Serving Entity (LSE). The MISO resource adequacy tariff would replace the NSP System current planning reserve obligations. In March 2008, the

Table of Contents

FERC issued an order approving the Module E tariff. Various parties requested rehearing of the FERC order. MISO is expected to start Module E on March 1, 2009.

Market Based Rate Rules — In June 2007, the FERC issued a final order governing its market-based rate authorizations to electric utilities. The FERC reemphasized its commitment to market-based pricing, but is revising the tests it uses to assess whether a utility has market power and has emphasized that it intends to exercise greater oversight where it has market-based rate authorizations. NSP-Minnesota has been granted market-based rate authority and will be subject to the new rule.

On Dec. 22, 2008, the NSP System submitted their Triennial Market Power Analysis to the FERC to support their market-based rate authority. Applying the FERC’s required tests, the Market Power Analysis submitted by the NSP System demonstrates that they have neither horizontal market power nor vertical market power in the relevant geographic market. Consequently, the NSP System has requested that the FERC permit them to retain their market-based rate authority.

Affiliate Transaction Rules — On Feb. 21, 2008, the FERC issued Order No. 707, which amended the FERC’s regulations to codify restrictions on affiliate transactions between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities, and their market-regulated power sales affiliates or non-utility affiliates. The Xcel Energy utility subsidiaries are subject to the new rules. The rules apply historic SEC “at cost” pricing standards to transactions between service companies of utility holding company systems and their FERC jurisdictional public utility affiliates. In September 2008, the National Rural Electric Cooperative Association and the American Public Power Association filed a petition for review of Order No. 707 with the U.S. Court of Appeals for the District of Columbia. The appeal is pending.

Electric Operating Statistics

	Year Ended Dec. 31,
	2008			2007			2006
Electric Sales (millions of Kwh)
Residential	1,938			1,958			1,924
Commercial and industrial	4,391			4,373			4,211
Public authorities and other	38			38			38
Total retail	6,367			6,369			6,173
Wholesale	553			575			571
Total energy sold	6,920			6,944			6,744

Number of customers at end of period
Residential	209,980			208,415			207,451
Commercial and industrial	37,315			36,754			36,334
Public authorities and other	1,154			1,144			1,141
Total retail	248,449			246,313			244,926
Wholesale	10			10			10
Total customers	248,459			246,323			244,936

Electric revenues (thousands of dollars)
Residential	$	200,982		$	183,264		$	178,324
Commercial and industrial	320,804			287,860			273,315
Public authorities and other	5,420			4,973			4,964
Total retail	527,206			476,097			456,603
Wholesale	32,768			32,403			27,785
Interchange revenues from NSP-Minnesota	106,363			120,218			99,403
Other electric revenues	(962		)	3,115			1,258
Total electric revenues	$	665,375		$	631,833		$	585,049

Kwh sales per retail customer	25,627			25,857			25,204
Revenue per retail customer	$	2,122		$	1,933		$	1,864
Residential revenue per Kwh	10.37		¢	9.36		¢	9.27		¢
Commercial and industrial revenue per Kwh	7.31			6.58			6.49
Wholesale revenue per Kwh	5.93			5.64			4.87

Table of Contents

NATURAL GAS UTILITY OPERATIONS

The most significant recent developments in the natural gas operations of NSP-Wisconsin are the continued volatility in natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 1998 to 2008, average annual sales to the typical NSP-Wisconsin residential customer declined from 86 MMBtu per year to 71 MMBtu per year on a weather-normalized basis. Although recent wholesale price increases do not directly affect earnings because of gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

For a further discussion of rate and regulatory matters see Note 12 to the consolidated financial statements.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. The filing procedure generally allows the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

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. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

For further discussion see Note 12 to the consolidated financial statements.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 143,216 MMBtu for 2008, which occurred on Jan. 30, 2008.

NSP-Wisconsin purchases natural gas from independent suppliers, which are generally priced 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 133,546 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These agreements provide storage for approximately 26 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 2008-2009 supply plan was approved by the PSCW in October 2008.

Natural Gas Supply and Costs

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

Table of Contents

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:

2008	$	8.54
2007	7.56
2006	8.42

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 2009 through 2027.

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, 2008, NSP-Wisconsin was committed to approximately $124 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 16 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2008		2007		2006
Natural gas sales (thousands of MMBtu)
Residential	7,155		6,510		5,750
Commercial and industrial	8,921		8,268		7,953
Other	443		1,884		865
Total retail	16,519		16,662		14,568
Transportation	3,828		3,923		3,245
Total deliveries	20,347		20,585		17,813

Number of customers at end of period
Residential	91,593		89,640		88,670
Commercial and industrial	12,132		11,934		11,771
Total retail	103,725		101,574		100,441
Transportation	22		22		22
Total customers	103,747		101,596		100,463

Natural gas revenues (thousands of dollars)
Residential	$	87,944	$	72,567	$	69,646
Commercial and industrial	90,211		73,590		77,407
Total retail	178,155		146,157		147,053
Transportation and other	1,279		2,684		2,189
Total natural gas revenues	$	179,434	$	148,841	$	149,242

MMBtu sales per retail customer	159.26		164.04		145.04
Revenue per retail customer	$	1,718	$	1,439	$	1,464
Residential revenue per MMBtu	12.29		11.15		12.11
Commercial and industrial revenue per MMBtu	10.11		8.90		9.73
Transportation and other revenue per MMBtu	0.33		0.68		0.67

Table of Contents

ENVIRONMENTAL MATTERS

NSP-Wisconsin 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-Wisconsin 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 13 to the consolidated financial statements.

EMPLOYEES

The number of full-time NSP-Wisconsin employees on Dec. 31, 2008 was 546. Of these full-time employees, 403, or 74 percent, are covered under collective bargaining agreements. See Note 7 in the consolidated financial statements for further discussion of the bargaining agreements. 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.

Item 1A — Risk Factors

Risks Associated with Our Business

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

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

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

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

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

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.

Table of Contents

Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs.

We are subject to interest rate risk.

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

We are subject to capital market risk.

NSP-Wisconsin’s operations require significant capital investment in property, plant and equipment; consequently, NSP-Wisconsin is an active participant in debt 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 events throughout the world economy. Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, could prevent NSP-Wisconsin from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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 overall economy and the price of products and services provided.

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.

NSP-Wisconsin may at times have direct credit exposure as part of its local gas distribution company supply activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. NSP-Wisconsin may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.

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

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

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

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

Table of Contents

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, 2008, these sites included:

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

· Third party sites, such as landfills, at 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 operating and maintenance 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, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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 an increase in changes in precipitation and extreme weather events. NSP-Wisconsin does not serve any coastal communities so the possibility of sea level rises does not directly affect NSP-Wisconsin or its 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 the company’s service territory could also have an impact on NSP-Wisconsin’s revenues. NSP-Wisconsin buys and sells 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 NSP-Wisconsin’s service territories, primarily through thunderstorms, tornadoes and snow or ice storms. We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so. 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 NSP-Wisconsin’s revenues. NSP-Wisconsin’s 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, 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, 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 NSP-Wisconsin to receive less than ideal terms and conditions.

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

Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of

Table of Contents

Congress. Likewise, the EPA has issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act. NSP-Wisconsin’s 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. NSP-Wisconsin is advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with our environmental leadership strategy.

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 emissions for their own operations.

Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a “cap and trade” structure, on NSP-Wisconsin and its 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. An important factor is NSP-Wisconsin’s ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on NSP-Wisconsin. If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion see Note 13 to the consolidated financial statements.

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the Capital Markets 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. It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur. See credit risk section for more related information.

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 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.

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 as our

Table of Contents

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 their licensed lives.

The NRC has authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota’s nuclear plants. In addition, the Institute for Nuclear Power Operations (INPO) reviews our nuclear operations and nuclear generation facilities. Compliance with INPO 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 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 our competitors and we typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption 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 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 or the actions of a neighboring utility. 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.

We are subject to business continuity risks associated with our ability to respond to unforeseen events.

The term business continuity refers to the ability of the firm to maintain day-to-day operations in response to unforeseen events, such as those in the preceding section, which describes numerous disruptions to our normal operating environment.

Table of Contents

While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations. The company’s response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm’s on-going business operations.

Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results. It’s difficult to predict the magnitude of such events and associated impacts.

We are subject to information security risks.

A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event.

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict 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 businesses, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.

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

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

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased 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 and FERC for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

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

We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding

Table of Contents

requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006, as amended, 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.

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

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

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

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 events were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2008, Xcel Energy had approximately $7.7 billion of long-term debt and $1.0 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 of specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2008, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $67.5 million and $18.2 million of exposure. Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries. The total amount of bonds with these indemnities outstanding as of Dec. 31, 2008, was approximately $27.9 million. Xcel Energy’s total exposure under these indemnities cannot be determined at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

We have historically paid quarterly dividends to Xcel Energy. In 2008, 2007 and 2006 we paid $62.5 million, $40.2 million and $42.4 million of dividends to Xcel Energy, respectively. If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs. This could adversely affect our liquidity. The amount of dividends that we can pay is also limited to some extent by our indenture for our first mortgage bonds.

Table of Contents

Item 1B — Unresolved SEC Staff Comments

None

Item 2 — Properties

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

Electric utility generating stations:

Station, City and Unit	Fuel	Installed	Summer 2008 Net Dependable Capability (MW)

*Steam:*
Bay Front-Ashland, WI
3 Units	Coal/Wood/Natural Gas	1948-1956	73
French Island-La Crosse, WI
2 Units	Wood/RDF (a)	1940-1948	29

*Combustion Turbine:*
Flambeau Station-Park Falls, WI	Natural Gas/Oil	1969	13
Wheaton-Eau Claire, WI
6 Units	Natural Gas/Oil	1973	353
French Island-La Crosse, WI
2 Units	Oil	1974	147

*Hydro:*
64 Units		Various	257
		Total	872

(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, 2008:

Conductor miles
345 KV		1,153
161 KV		1,393
115 KV		1,529
Less than 115 KV		31,911

NSP-Wisconsin had 203 electric utility transmission and distribution substations at Dec. 31, 2008.

Natural gas utility mains at Dec. 31, 2008:

Miles
Distribution		2,189

Item 3 — Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against NSP-Wisconsin. Management, after consultation with legal counsel, 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 13 to the consolidated financial statements. For a discussion of proceedings involving utility rates, see Public Utility Regulation and Summary of Recent Federal Regulatory Developments under Item 1 and Note 12 to the consolidated financial statements.

Table of Contents

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

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

PART II

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

NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy and there is no market for its common equity securities.

NSP-Wisconsin’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy. In addition, dividends paid by NSP-Wisconsin are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

The dividends declared during 2008 and 2007 were as follows:

Quarter Ended (Thousands of Dollars)
March 31, 2008		June 30, 2008		Sept. 30, 2008		Dec. 31, 2008
$	9,366	$	9,327	$	34,312	$	8,583

Quarter Ended (Thousands of Dollars)
March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007
$	10,043	$	9,988	$	9,642	$	9,523

Item 6 — Selected Financial Data

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

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

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

Forward Looking Information

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of NSP-Wisconsin 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; 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, 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,

Table of Contents

investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of NSP-Wisconsin’s Form 10-K for the year ended Dec. 31, 2008.

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

Results of Operations

NSP-Wisconsin’s net income was approximately $45.5 million for 2008, compared with approximately $37.9 million for 2007.

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 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.

Electric — The following tables detail the change in electric revenues and margin:

(Millions of Dollars)	2008			2007
Electric revenues	$	665		$	632
Electric fuel and purchased power	(385		)	(373		)
Electric margin	$	280		$	259

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

Electric Revenues

(Millions of Dollars)	2008 vs. 2007
Retail rate increases	$	33
Fuel cost recovery	17
Sales mix	4
Sales growth (excluding weather impact)	3
Revenues due to leap year (weather normalized impact)	1
Interchange agreement billing with NSP-Minnesota	(19		)
Estimated impact of weather	(5		)
Other	(1		)
Total increase in electric revenues	$	33

Electric Margin

(Millions of Dollars)	2008 vs. 2007
Base rate changes	$	33
Fuel cost recovery	9
Sales mix	4
Sales growth (excluding weather impact)	3
Firm wholesale	1
Revenues due to leap year (weather normalized impact)	1
Interchange agreement billing with NSP-Minnesota	(20		)
Estimated impact of weather	(5		)
Purchased capacity costs	(3		)
Other	(2		)
Total increase in electric margin	$	21

Table of Contents

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.

Natural Gas — The following table details the change in natural gas revenues and margin:

(Millions of Dollars)	2008			2007
Natural gas revenues	$	179		$	149
Cost of natural gas sold and transported	(137		)	(113		)
Natural gas margin	$	42		$	36

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

Natural Gas Revenues

(Millions of Dollars)	2008 vs. 2007
Purchased natural gas cost recovery	$	25
Base rate changes	4
Estimated impact of weather	2
Other	(1		)
Total increase in natural gas revenues	$	30

Natural Gas Margin

(Millions of Dollars)	2008 vs. 2007
Base rate changes	$	4
Estimated impact of weather	2
Total increase in natural gas margin	$	6

Operating and Maintenance Expenses — Operating and maintenance expenses for 2008 increased $2.2 million, or 1.7 percent, compared with 2007. The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2008 vs. 2007
Higher interchange expense with NSP-Minnesota	$	4
Higher power plant operating costs	2
Lower license fees and permit costs	(2		)
Lower employee benefit costs	(2		)
Total increase in operating and maintenance expenses	$	2

Conservation Program Expenses — Conservation program expenses increased approximately $2.8 million, or 37.1 percent, for 2008 compared with 2007. The higher expense is attributable to the ongoing expansion of such programs as designed, in part, to meet certain regulatory commitments.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $4.2 million, or 7.8 percent, for 2008 compared with 2007. The increase was primarily due to planned system expansion and an increase in the amortization of regulatory assets.

Taxes (other than income taxes) — Taxes (other than income taxes) increased by approximately $1.3 million, or 6.5 percent, for 2008 compared with 2007. The increase was primarily due to higher gross receipts tax paid to the state of Wisconsin as a result of higher gross revenues.

AFDC — AFDC, equity and debt, decreased in total by approximately $0.7 million for 2008 compared with 2007. The decrease was primarily due to the completion of certain projects.

Table of Contents

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2008			2007			2006
Operating revenues
Electric	$	665,375		$	631,833		$	585,049
Natural gas	179,434			148,841			149,242
Other	910			843			782
Total operating revenues	845,719			781,517			735,073

Operating expenses
Electric fuel and purchased power	385,180			372,940			322,647
Cost of natural gas sold and transported	136,790			113,179			116,242
Operating and maintenance expenses	137,587			135,347			129,221
Conservation program expenses	10,170			7,418			7,418
Depreciation and amortization	58,335			54,120			51,852
Taxes (other than income taxes)	20,989			19,702			18,565
Total operating expenses	749,051			702,706			645,945

Operating income	96,668			78,811			89,128

Interest and other income, net	317			1,483			257
Allowance for funds used during construction — equity	898			1,233			718

Interest charges and financing costs:
Interest charges — including financing costs of $1,325, $1,252 and $1,256, respectively	25,641			22,967			23,149
Allowance for funds used during construction — debt	(1,053		)	(1,424		)	(1,188		)
Total interest charges and financing costs	24,588			21,543			21,961

Income before income taxes	73,295			59,984			68,142
Income taxes	27,774			22,118			24,468
Net income	$	45,521		$	37,866		$	43,674

See Notes to Consolidated Financial Statements

Table of Contents

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2008			2007			2006
Operating activities
Net income	$	45,521		$	37,866		$	43,674
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	61,142			56,538			53,805
Deferred income taxes	1,305			8,907			(9,959		)
Amortization of investment tax credits	(629		)	(695		)	(761		)
Allowance for bad debts	4,784			4,235			5,984
Allowance for equity funds used during construction	(898		)	(1,233		)	(718		)
Net realized and unrealized hedging and derivative transactions	457			228			970
Changes in operating assets and liabilities
Accounts receivable	10,000			(10,201		)	367
Accrued unbilled revenues	(5,599		)	(4,939		)	7,825
Inventories	(5,953		)	(7,239		)	1,810
Other current assets	(1,730		)	(2,142		)	(1,798		)
Accounts payable	(1,086		)	13,390			(7,110		)
Net regulatory assets and liabilities	4,840			(4,854		)	9,171
Other current liabilities	13,470			(3,019		)	802
Change in other noncurrent assets	1,733			1,357			(921		)
Change in other noncurrent liabilities	(1,023		)	(4,591		)	7,483
Net cash provided by operating activities	126,334			83,608			110,624

Investing activities
Utility capital/construction expenditures	(93,736		)	(80,149		)	(57,551		)
Allowance for equity funds used during construction	898			1,233			718
Other investments	(6,565		)	1,211			206
Net cash used in investing activities	(99,403		)	(77,705		)	(56,627		)

Financing activities
Proceeds from notes payable to affiliate	337,600			371,250			345,500
Repayment of notes payable to affiliate	(396,200		)	(343,050		)	(379,200		)
Proceeds from issuance of long-term debt	196,370			—			192
Repayment of long-term debt	(80,065		)	(62		)	—
Capital contributions from parent	8,751			5,758			22,393
Dividends paid to parent	(62,527		)	(40,210		)	(42,401		)
Net cash provided by (used in) provided by financing activities	3,929			(6,314		)	(53,516		)

Net increase (decrease) in cash and cash equivalents	30,860			(411		)	481
Cash and cash equivalents at beginning of year	751			1,162			681
Cash and cash equivalents at end of year	$	31,611		$	751		$	1,162
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	20,709		$	20,632		$	21,426
Cash paid for income taxes (net of refunds received)	15,768			15,732			39,607

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	2,017		$	1,845		$	2,315

See Notes to Consolidated Financial Statements

Table of Contents

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31
	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	31,611		$	751
Accounts receivable, net	56,518			69,183
Accounts receivable from affiliates	599			2,718
Accrued unbilled revenues	42,639			37,040
Inventories	39,476			33,523
Prepaid taxes	18,377			17,041
Deferred income taxes	3,389			13,532
Prepayments and other	10,401			2,960
Total current assets	203,010			176,748

Property, plant and equipment, net	1,010,683			975,609

Other assets:
Regulatory assets	189,753			114,373
Prepaid pension asset	—			40,681
Other investments	4,196			4,902
Other	6,031			4,959
Total other assets	199,980			164,915
Total assets	$	1,413,673		$	1,317,272

Liabilities and Equity
Current liabilities:
Current portion of long-term debt	$	250		$	80,266
Notes payable to affiliate	650			59,250
Accounts payable	44,555			37,454
Accounts payable to affiliates	17,600			25,691
Dividends payable to parent	8,583			9,522
Accrued taxes	7,996			493
Accrued interest	6,513			4,105
Derivative instruments valuation	1,869			460
Other	15,089			11,740
Total current liabilities	103,105			228,981
Deferred credits and other liabilities:
Deferred income taxes	174,969			181,506
Regulatory liabilities	105,298			103,327
Pension and employee benefit obligations	40,383			26,328
Customer advances	17,624			18,462
Deferred investment tax credits	10,366			10,995
Environmental liabilities	68,018			42,705
Other	1,815			3,966
Total deferred credits and other liabilities	418,473			387,289
Minority interest in subsidiaries	154			212
Commitments and contingent liabilities
Capitalization:
Long-term debt	433,905			235,402
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares	93,300			93,300
Additional paid in capital	124,708			115,957
Retained earnings	240,770			256,951
Accumulated other comprehensive loss	(742		)	(820		)
Total common stockholder’s equity	458,036			465,388
Total liabilities and equity	$	1,413,673		$	1,317,272

See Notes to Consolidated Financial Statements

Table of Contents

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(amounts in thousands of dollars, except share data)

									Accumulated			Total
				Additional					Other			Common
	Common Stock			Paid in		Retained			Comprehensive			Stockholder’s
	Shares	Amount		Capital		Earnings			Income (Loss)			Equity

Balance at Dec. 31, 2005	933,000	$	93,300	$	87,806	$	257,346		$	(969	)	$	437,483

Net income						43,674						43,674
Net derivative instrument fair value changes during the period, net of tax of $57									70			70
Comprehensive income for 2006												43,744
Common dividends declared to parent						(42,339		)				(42,339		)
Contribution of capital by parent				22,393								22,393
Balance at Dec. 31, 2006	933,000	$	93,300	$	110,199	$	258,681		$	(899	)	$	461,281

FIN 48 adoption						(400		)				(400		)
Net income						37,866						37,866
Net derivative instrument fair value changes during the period, net of tax of $48									79			79
Comprehensive income for 2007												37,945
Common dividends declared to parent						(39,196		)				(39,196		)
Contribution of capital by parent				5,758								5,758
Balance at Dec. 31, 2007	933,000	$	93,300	$	115,957	$	256,951		$	(820	)	$	465,388

EITF 06-4 adoption, net of tax of $(72)						(114		)				(114		)
Net income						45,521						45,521
Net derivative instrument fair value changes during the period, net of tax of $49									78			78
Comprehensive income for 2008												45,599
Common dividends declared to parent						(61,588		)				(61,588		)
Contribution of capital by parent				8,751								8,751
Balance at Dec. 31, 2008	933,000	$	93,300	$	124,708	$	240,770		$	(742	)	$	458,036

See Notes to Consolidated Financial Statements

Table of Contents

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars)

	Dec. 31
	2008			2007
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
Dec. 1, 2026, 7.375%	65,000			65,000
Sept. 1, 2038, 6.375%	200,000			—
Senior Notes due Oct. 1, 2008, 7.64%	—			80,000
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% (a)	18,600			18,600
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%	726			760
Other	2,062			2,094
Unamortized discount	(2,233		)	(786		)
Total	434,155			315,668
Less current maturities	250			80,266
Total long-term debt	$	433,905		$	235,402

Common Stockholder’s Equity
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares in 2008 and 2007	$	93,300		$	93,300
Additional paid in capital	124,708			115,957
Retained earnings	240,770			256,951
Other comprehensive loss	(742		)	(820		)
Total common stockholder’s equity	$	458,036		$	465,388

(a) Resource recovery financing

See Notes to Consolidated Financial Statements

Table of Contents

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 estimated. 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 purchased natural gas and electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, 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 costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. A summary of significant rate adjustment mechanisms follows:

· NSP-Wisconsin’s rates in Wisconsin include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. In Wisconsin, 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.

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

Fair Value Measurements — NSP-Wisconsin presents cash equivalents and commodity derivatives at estimated fair value 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 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 as primary inputs to determine fair value.

Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.

Gains or losses on hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs and interest rate hedging transactions are recorded as a component of interest expense. NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Cash Flow Hedges — Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The designation of a cash flow hedge permits changes in fair value to be recorded within other comprehensive income (OCI), to the extent the hedge is effective, or deferred as a regulatory asset or liability.

Table of Contents

SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. NSP-Wisconsin formally documents all hedging relationships in accordance with SFAS No. 133. The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction. In addition, at inception and on a quarterly basis, NSP-Wisconsin formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.

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

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

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and, if so, if they qualify to meet the normal purchases and normal sales designation requirements under SFAS No. 133. For further discussion of NSP-Wisconsin’s risk management and derivative activities, see Note 9 to the consolidated financial statements.

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

NSP-Wisconsin records depreciation expense related to its plant by using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2008, 2007 and 2006 is 3.5 percent, 3.5 percent and 3.4 percent, respectively.

AFDC — AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.

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

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

Table of Contents

recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

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

Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method under FAS 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. NSP-Wisconsin uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

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

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

In July 2006, the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax positions that such company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, NSP-Wisconsin adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

NSP-Wisconsin reports interest and penalties related to income taxes within the interest charges section in the consolidated statements of income.

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

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

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

Inventory — All inventories are recorded at average cost.

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

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

Table of Contents

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

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. If restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Wisconsin’s results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 14 to the consolidated financial statements.

Deferred Financing Costs — Other assets include deferred financing costs, net of amortization, of approximately $3.4 million and $1.5 million at Dec. 31, 2008 and 2007, respectively. NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

Debt premiums, discounts, expenses and amounts received or paid to settle hedges are amortized over the life of the related debt. The premiums and costs associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. If NSP-Wisconsin extinguishes the debt, all unamortized balances shall be expensed at the time of the redemption.

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

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

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

Reclassifications — Conservation program expenses were reclassified as a separate item from other operating and maintenance expenses on the consolidated statements of income. Activity from the allowance for bad debts was reclassified from the change in accounts receivable on the consolidated statements of cash flows. These reclassifications did not have an impact on total operating expenses or net cash provided by operating activities.

2. Accounting Pronouncements

Recently Issued

Business Combinations (SFAS No. 141 (revised 2007)) — In December 2007, the FASB issued SFAS No. 141R, which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. NSP-Wisconsin will apply SFAS No. 141R to business combinations occurring subsequent to Jan. 1, 2009.

Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This statement is effective for fiscal years and interim periods

Table of Contents

beginning on or after Dec. 15, 2008. NSP-Wisconsin does not expect the implementation of SFAS No. 160 to have a material impact on its consolidated financial statements.

Disclosures about Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133 (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008, with early application encouraged. NSP-Wisconsin does not expect the implementation of SFAS No. 161 to have a material impact on its consolidated financial statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) — In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand on an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk. FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009. NSP-Wisconsin does not expect the implementation of FSP FAS 132(R)-1 to have a material impact on its consolidated financial statements.

Recently Adopted

Fair Value Measurements (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.

On Jan. 1, 2008, NSP-Wisconsin adopted SFAS No. 157 for all assets and liabilities measured at fair value except for non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis, as permitted by FSP FAS 157-2, Effective Date of FASB Statement No. 157. The adoption did not have a material impact on NSP-Wisconsin’s consolidated financial statements. For additional discussion and SFAS No. 157 required disclosures, see Note 11 to the consolidated financial statements.

The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) — In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement was effective for fiscal years beginning after Nov. 15, 2007. NSP-Wisconsin adopted SFAS No. 159 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (FSP FAS 157-3) — In October 2008, the FASB issued FSP FAS 157-3, which clarifies the application of SFAS No. 157 in a market that is not active. FSP FAS 157-3 was effective immediately upon issuance, and applied to prior periods for which financial statements had not yet been issued. NSP-Wisconsin adopted FSP FAS 157-3 as of Sept. 30, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance

Arrangements (Emerging Issues Task Force (EITF) Issue No. 06-4) — In June 2006, the EITF reached a consensus on EITF No. 06-4, which provides guidance on the recognition of a liability and related compensation costs for endorsement split-dollar life insurance policies that provide a benefit to an employee that extends to postretirement periods. Therefore, this EITF would not apply to a split-dollar life insurance arrangement that provides a specified benefit to an employee that is limited to the employee’s active service period with an employer. EITF No. 06-4 was effective for fiscal years beginning after Dec. 15, 2007, with earlier application permitted. Upon adoption of EITF No. 06-4 on Jan. 1, 2008, NSP-Wisconsin

Table of Contents

recorded a liability of $0.1 million, net of tax, as a reduction of retained earnings. Thereafter, changes in the liability are reflected in operating results.

Amendment of FASB Interpretation No. 39 (FSP FIN 39-1) — In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, Offsetting of Amounts Related to Certain Contracts, to permit companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FSP FIN 39-1 was effective for fiscal years beginning after Nov. 15, 2007. NSP-Wisconsin adopted FSP FIN 39-1 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11) — In June 2007, the EITF reached a consensus on EITF No. 06-11, which states that an entity should recognize a realized tax benefit associated with dividends on nonvested equity shares and nonvested equity share units charged to retained earnings as an increase in additional paid in capital. The amount recognized in additional paid in capital should be included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. EITF No. 06-11 was to be applied prospectively to income tax benefits of dividends on equity-classified share-based payment awards that were declared in fiscal years beginning after Dec. 15, 2007. NSP-Wisconsin adopted EITF No. 06-11 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

The Hierarchy of GAAP (SFAS No. 162) — In May 2008, the FASB issued SFAS No. 162, which establishes the GAAP hierarchy, identifying the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements. SFAS No. 162 was effective Nov. 15, 2008. NSP-Wisconsin adopted SFAS No. 162 on Dec. 31, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities (FSP FAS 140-4 and FIN 46(R)-8) — In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to require public entities to provide additional disclosures about transfers of financial assets. It also amends FIN 46 (revised December 2003), Consolidation of Variable Interest Entities, to require public enterprises, including sponsors that have a variable interest in a variable interest entity, to provide additional disclosures about their involvement with variable interest entities. FSP FAS 140-4 and FIN 46(R)-8 was effective for the interim and annual periods ending after Dec. 15, 2008. NSP-Wisconsin adopted FSP FAS 140-4 and FIN 46(R)-8 on Dec. 31, 2008, and the adoption did not have a material impact on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2008			Dec. 31, 2007
Accounts receivable, net:
Accounts receivable	$	61,176		$	72,013
Less allowance for bad debts	(4,658		)	(2,830		)
	$	56,518		$	69,183

Inventories:
Materials and supplies	$	4,592		$	4,283
Fuel	13,156			13,457
Natural gas	21,728			15,783
	$	39,476		$	33,523

Property, plant and equipment, net:
Electric utility plant	$	1,434,233		$	1,338,188
Natural gas utility plant	172,131			167,593
Common utility and other property	111,133			108,289
Construction work in progress	30,494			52,705
Total property, plant and equipment	1,747,991			1,666,775
Less accumulated depreciation	(737,308		)	(691,166		)
	$	1,010,683		$	975,609

Table of Contents

4. Short-Term Borrowings

NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate. NSP-Wisconsin has board approval to issue up to $100 million under the arrangement. At Dec. 31, 2007, NSP-Wisconsin had short-term borrowings under this intercompany arrangement of $58.6 million with a weighted average interest rate of 5.58 percent. NSP-Wisconsin had no short-term borrowings at Dec. 31, 2008.

Clearwater Investments Inc., an NSP-Wisconsin subsidiary, also had notes payable outstanding as of Dec. 31, 2008 and 2007 to Xcel Energy, in the amount of $0.7 million. The weighted average interest rates at Dec. 31, 2008 and 2007 were 3.34 percent and 5.52 percent, respectively.

5. Long-Term Debt

On Sept. 10, 2008, NSP-Wisconsin issued $200 million of 6.375 percent first mortgage bonds, series due Sept. 1, 2038. NSP-Wisconsin added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of such net proceeds to fund the payment at maturity of $80 million of 7.64 percent senior notes due Oct. 1, 2008. The balance of the net proceeds was used for the repayment of short-term debt (including notes payable to affiliates) and for general corporate purposes.

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

Maturities of long-term debt are:

(Millions of Dollars)
2009	$	0.3
2010	1.4
2011	—
2012	—
2013	—

On Jan. 14, 2009, NSP-Wisconsin announced a tender for and repurchase of any and all principal amount and accrued interest of the remaining 7.375 percent $65 million first mortgage bonds due Dec. 1, 2026 with the tender period running through March 1, 2009. The net costs are anticipated to be $3.0 million related to this repayment of debt and will be recorded in the first quarter of 2009. The debt repayment will be funded by existing cash resources.

6. Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated income tax returns. In the first quarter of 2008, the IRS completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009. In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007. As of Dec. 31, 2008, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

As of Dec. 31, 2008, NSP-Wisconsin’s earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

Table of Contents

The amount of unrecognized tax benefits was $0.9 million and $1.5 million on Dec. 31, 2007 and 2008, respectively. A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2008		2007
Balance at Jan. 1	$	0.9	$	1.6
Additions based on tax positions related to the current year	0.5		0.7
Additions for tax positions of prior years	0.1		0.1
Reductions for tax positions of prior years	—		(0.7		)
Settlements with taxing authorities	—		(0.8		)
Balance at Dec. 31	$	1.5	$	0.9

The unrecognized tax benefit balance included $0.1 million and $0.2 million of tax positions on Dec. 31, 2007 and 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $0.8 million and $1.3 million of tax positions on Dec. 31, 2007 and 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The increase in the unrecognized tax benefit balance of $0.6 million from Dec. 31, 2007 to Dec. 31, 2008, was due to the addition of similar uncertain tax positions related to ongoing activity. NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

The liability for interest related to unrecognized tax benefits on Dec. 31, 2007, and the change in the interest expense related to unrecognized tax benefits reported within interest charges in 2007 was not material. The amount of interest expense related to unrecognized tax benefits reported within interest charges in 2008 was $0.1 million. The liability for interest related to unrecognized tax benefits was $0.1 million on Dec. 31, 2008. No amounts were accrued for penalties as of Dec. 31, 2007 and 2008.

Other Income Tax Matters — NSP-Wisconsin’s federal net operating loss carryforward is estimated to be $3.2 million and $3.1 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. NSP-Wisconsin’s federal tax credit carryforward is estimated to be $1.3 million and $1.3 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. The carryforward periods expire between 2021 and 2027.

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

	2008		2007		2006
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	5.2		4.9		4.2
Tax credits recognized, net of federal income tax expense	(0.9	)	(1.2	)	(1.1	)
Resolution of income tax audits and other	—		(0.2	)	(1.1	)
Regulatory differences — utility plant items	(1.3	)	(0.7	)	(0.4	)
FIN 48 expense — unrecognized tax benefits	0.1		(0.5	)	—
Life insurance policies	(0.1	)	(0.1	)	(0.1	)
Other, net	(0.1	)	(0.3	)	(0.6	)
Effective income tax rate	37.9	%	36.9	%	35.9	%

Table of Contents

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2008			2007			2006
Current federal tax expense	$	20,137		$	12,089		$	29,830
Current state tax expense	6,336			2,553			5,358
Current FIN 48 tax expense (benefit)	625			(737		)	—
Deferred federal tax expense (benefit)	2,409			6,653			(7,726		)
Deferred state tax (benefit) expense	(557		)	1,845			(2,233		)
Deferred FIN 48 tax (benefit) expense	(547		)	409			—
Deferred investment tax credits	(629		)	(694		)	(761		)
Total income tax expense	$	27,774		$	22,118		$	24,468

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

(Thousands of Dollars)	2008			2007
Deferred tax expense excluding items below	$	3,606		$	10,766
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(2,252		)	(3,020		)
FIN 48 adoption: Deferred tax expense reported as an adjustment to the beginning balance of retained earnings	—			1,209
Tax benefit allocated to other comprehensive income and other	(49		)	(48		)
Deferred tax expense	$	1,305		$	8,907

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

(Thousand of Dollars)	2008		2007
Deferred tax liabilities:
Differences between book and tax bases of property	$	158,213	$	145,893
Regulatory assets	38,515		30,197
Employee benefits	16,379		16,430
Wisconsin annual license fee	7,369		6,808
Other	318		165
Total deferred tax liabilities	$	220,794	$	199,493

Deferred tax assets:
Environmental remediation	$	27,688	$	17,642
Regulatory liabilities	5,063		5,350
Deferred investment tax credits	4,157		4,393
Rate refund	3,926		—
Net operating loss carry forward	1,617		1,325
Tax credit carry forward	1,275		1,275
Bad debts	1,868		1,131
Other	3,620		403
Total deferred tax assets	$	49,214	$	31,519
Net deferred tax liability	$	171,580	$	167,974

7. Benefit Plans and Other Postretirement Benefits

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

Xcel Energy offers various benefit plans to its employees, including those of NSP-Wisconsin. Approximately 50 percent of Xcel Energy employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2008, NSP-Wisconsin had 403 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2010.

Table of Contents

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R) (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. NSP-Wisconsin applied regulatory accounting treatment for unrecognized amounts of regulated utility subsidiary employees, which allowed recognition as a regulatory asset rather than as a charge to accumulated other comprehensive income, as future costs are expected to be included in rates. The effect of adopting in 2006 for the remaining unrecognized amounts had no net effect on accumulated other comprehensive income.

Pension Benefits

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

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

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 52 percent in equity investments, 25 percent in fixed income investments and 23 percent in nontraditional investments, such as real estate, private equity and a diversified commodities index.

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

	2008		2007
Equity securities	55	%	60	%
Debt securities	26		22
Real estate	5		4
Cash	3		2
Nontraditional investments	11		12
	100	%	100	%

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 9.56 percent, which is greater than the current assumption level. The pension cost determination assumes the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments. A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2008 and 2007 were below the assumed level of 8.75 percent while returns in 2006 exceeded the assumed level of 8.75 percent. Xcel Energy continually reviews its pension assumptions. In 2009, Xcel Energy will use an investment-return assumption of 8.50 percent.

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

(Thousands of Dollars)	2008				2007
Accumulated Benefit Obligation at Dec. 31	$	2,435,513			$	2,497,898

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,662,759			$	2,666,555
Service cost	62,698				61,392
Interest cost	167,881				162,774
Plan amendments	—				(19,955			)
Actuarial (gain) loss	(47,509			)	23,325
Benefit payments	(247,797			)	(231,332			)
Obligation at Dec. 31	$		2,598,032		$		2,662,759

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	3,186,273			$	3,183,375
Actual (loss) return on plan assets	(788,273			)	199,230
Employer contributions	35,000				35,000
Benefit payments	(247,797			)	(231,332			)
Fair value of plan assets at Dec. 31	$	2,185,203			$	3,186,273

Funded Status of Plans at Dec. 31:
Funded status	$	(412,829		)	$	523,514
Noncurrent assets	15,612				568,055
Noncurrent liabilities	(428,441			)	(44,541			)
Net pension amounts recognized on consolidated balance sheets	$	(412,829		)	$	523,514

NSP-Wisconsin accrued benefit liability recorded	$	13,675			$	—
NSP-Wisconsin prepaid pension asset recorded	—				40,681

Table of Contents

(Thousands of Dollars)	2008			2007
NSP-Wisconsin Amounts Recognized in Accumulated Other Comprehensive Income:
Components:
Net loss	$	65,172		$	8,146
Prior service cost	6,549			8,178
Total	$	71,721		$	16,324

SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	71,721		$	16,324
Total	$	71,721		$	16,324

Measurement Date	Dec. 31, 2008			Dec. 31, 2007

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.75		%	6.25		%
Expected average long-term increase in compensation level	4.00			4.00
Mortality table	RP 2000			RP 2000

At Dec. 31, 2008, one of Xcel Energy’s pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million. At Dec. 31, 2007, the plan assets of $369.8 million exceeded projected benefit obligations of $253.6 million. All other Xcel Energy plans in the aggregate had plan assets of $1.9 billion and $2.8 billion and projected benefit obligations of $2.4 billion and $2.4 billion on Dec. 31, 2008 and 2007.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2006 through 2008 for Xcel Energy’s pension plans and are not expected to require cash funding in 2009.

· Voluntary contributions were made to the PSCo Bargaining Pension Plan of $35 million in 2008, $35 million in 2007 and $30 million in 2006.

· Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $2 million in 2006. No voluntary contributions were made to the plan during 2007 or 2008.

· Xcel Energy projects cash funding of $70 million to $130 million in 2009. Pension funding contributions for 2010, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $150 million to $250 million.

Table of Contents

Plan Changes — The Pension Protection Act of 2006 (PPA) was effective Dec. 31, 2006. PPA requires a change in the conversion basis for lump-sum payments and three-year vesting for plans with account balance or pension equity benefits. These changes are reflected as a plan amendment for purposes of SFAS No. 87, Employers’ Accounting for Pensions.

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

(Thousands of Dollars)	2008			2007			2006
Service cost	$	62,698		$	61,392		$	61,627
Interest cost	167,881			162,774			155,413
Expected return on plan assets	(274,338		)	(264,831		)	(268,065		)
Amortization of prior service cost	20,584			25,056			29,696
Amortization of net loss	11,156			15,845			17,353
Net periodic pension (credit) cost under SFAS No. 87	$	(12,019	)	$	236		$	(3,976	)

NSP-Wisconsin:
Net periodic pension credit	$	(1,041	)	$	(978	)	$	(1,260	)

Significant Assumptions Used to Measure Costs:
Discount rate	6.25		%	6.00		%	5.75		%
Expected average long-term increase in compensation level	4.00			4.00			3.50
Expected average long-term rate of return on assets	8.75			8.75			8.75

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2009 pension cost calculations will be 8.50 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

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

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for NSP-Wisconsin were approximately $0.9 million in 2008 and 2007 and $0.8 million in 2006.

Postretirement Health Care Benefits

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

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

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106.

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

Table of Contents

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

	2008		2007
Equity and equity mutual fund securities	49	%	67	%
Fixed income/debt securities	29		21
Cash equivalents	22		11
Nontraditional investments	—		1
	100	%	100	%

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

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

(Thousands of Dollars)	2008			2007
Change in Benefit Obligation:
Obligation at Jan. 1	$	830,315		$	918,693
Service cost	5,350			5,813
Interest cost	51,047			50,475
Medicare subsidy reimbursements	6,178			2,526
Plan participants’ contributions	13,892			13,211
Actuarial gain	(46,827		)	(86,576		)
Benefit payments	(65,358		)	(73,827		)
Obligation at Dec. 31	$	794,597		$	830,315

(Thousands of Dollars)	2008				2007
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	427,459			$	406,305
Actual (loss) return on plan assets	(132,226			)	24,623
Plan participants’ contributions	13,892				13,211
Employer contributions	55,799				57,147
Benefit payments	(65,358			)	(73,827			)
Fair value of plan assets at Dec. 31	$	299,566			$	427,459

Funded Status at Dec. 31:
Funded status	$	(495,031		)	$	(402,856		)
Current liabilities	(4,928			)	(1,755			)
Noncurrent liabilities	(490,103			)	(401,101			)
Net amounts recognized on consolidated balance sheets	$	(495,031		)	$	(402,856		)

NSP-Wisconsin Amounts Recognized in Accumulated Other Comprehensive Income:
Components:
Net loss	$	14,982			$	15,965
Net transition obligations	685				856
Total	$	15,667			$	16,821

SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	15,667			$	16,821
Total	$	15,667			$	16,821

NSP-Wisconsin accrued benefit liability recorded	$	23,908			$	23,667

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.75			%	6.25			%
Mortality table	RP		2000		RP		2000

Table of Contents

Effective Dec. 31, 2008, Xcel Energy reduced its initial medical trend assumption from 8.0 percent to 7.4 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is five years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

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

(Thousands of Dollars)
1-percent increase in APBO components at Dec. 31, 2008	$	2,720
1-percent decrease in APBO components at Dec. 31, 2008	(2,295		)
1-percent increase in service and interest components of the net periodic cost	226
1-percent decrease in service and interest components of the net periodic cost	(187		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy contributed $55.6 million during 2008 and expects to contribute approximately $63.1 million during 2009.

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

(Thousands of Dollars)	2008			2007			2006
Service cost	$	5,350		$	5,813		$	6,633
Interest cost	51,047			50,475			52,939
Expected return on plan assets	(31,851		)	(30,401		)	(26,757		)
Amortization of transition obligation	14,577			14,577			14,444
Amortization of prior service credit	(2,175		)	(2,178		)	(2,178		)
Amortization of net loss	11,498			14,198			24,797
Net periodic postretirement benefit cost under SFAS No. 106	$	48,446		$	52,484		$	69,878

NSP-Wisconsin:
Net periodic postretirement benefit cost recognized — SFAS No. 106	$	2,011		$	1,914		$	2,638

Significant assumptions used to measure costs (income):
Discount rate	6.25		%	6.00		%	5.75		%
Expected average long-term rate of return on assets (before tax)	7.50			7.50			7.50

Projected Benefit Payments

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

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2009	$	224,558	$	62,975	$	5,725	$	57,250
2010	226,585		64,468		6,117		58,351
2011	226,446		66,390		6,433		59,957
2012	230,763		67,400		6,804		60,596
2013	234,149		68,008		7,127		60,881
2014-2018	1,237,114		351,249		38,796		312,453

Table of Contents

8. Detail of Interest and Other Income (Expense), Net

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

(Thousands of Dollars)	2008			2007			2006
Interest income	$	108		$	1,890		$	679
Other nonoperating income	199			66			118
Equity expense in unconsolidated affiliates	(6		)	(12		)	(16		)
Insurance policy income (expense)	16			(461		)	(524		)
Total interest and other income, net	$	317		$	1,483		$	257

9. Derivative Instruments

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. NSP-Wisconsin utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.

Commodity Price Risk — NSP-Wisconsin is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for natural gas used in its natural gas utility operations. Commodity risk is also managed through the use of financial derivative instruments. NSP-Wisconsin utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though the regulatory jurisdiction may provide for recovery of actual costs. NSP-Wisconsin’s risk-management policy allows it to manage commodity price risk with each rate-regulated operation 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, subject to regulatory approval when required.

Types of and Accounting for Derivative Instruments

NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation.

Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The types of qualifying hedging transactions that NSP-Wisconsin is currently engaged in are discussed below.

Cash Flow Hedges

Commodity Cash Flow Hedges — NSP-Wisconsin enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. Certain derivative instruments entered into to manage this variability are designated as cash flow hedges for accounting purposes. At Dec. 31, 2008, NSP-Wisconsin had various commodity-related contracts designated as cash flow hedges extending through March 2009. Changes in the fair value of cash flow hedges are recorded in other comprehensive income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place.

At Dec. 31, 2008, NSP-Wisconsin had no amounts in accumulated other comprehensive income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

NSP-Wisconsin had immaterial ineffectiveness related to commodity cash flow hedge contracts during 2008 and 2007.

Table of Contents

Interest Rate Cash Flow Hedges — NSP-Wisconsin enters into interest rate lock agreements, including treasury-rate locks and forward starting swaps, that effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.

At Dec. 31, 2008, NSP-Wisconsin had $0.1 million of net losses in accumulated other comprehensive income related to interest rate hedges that are expected to be recognized in earnings during the next 12 months.

NSP-Wisconsin had no ineffectiveness related to interest rate cash flow hedges during 2008 and 2007.

The following table shows the major components of the derivative instruments valuation in the consolidated balance sheets at Dec. 31:

	2008				2007
(Thousands of Dollars)	Derivative Instruments Valuation- Assets (a)		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets (a)		Derivative Instruments Valuation - Liabilities
Natural gas hedging derivative instruments	$	2	$	1,869	$	226	$	460
Total	$	2	$	1,869	$	226	$	460

(a) Amounts included in prepayments and other in the consolidated balance sheets.

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

(Millions of Dollars)
Accumulated other comprehensive loss related to hedges at Dec. 31, 2005	$	(1.0	)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1
Accumulated other comprehensive loss related to hedges at Dec. 31, 2006	$	(0.9	)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1
Accumulated other comprehensive loss related to hedges at Dec. 31, 2007	$	(0.8	)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1
Accumulated other comprehensive loss related to hedges at Dec. 31, 2008	$	(0.7	)

10. Financial Instruments

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

	2008				2007
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	160	$	160	$	109	$	109
Long-term debt, including current portion	434,155		438,050		315,668		314,609

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair value of NSP-Wisconsin’s long-term debt is estimated based on the quoted market prices for the same or similar issues or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2008 and 2007. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date and current estimates of fair values may differ significantly.

NSP-Wisconsin provides a guarantee for payment or performance under a specified agreement. As a result, NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the specified agreement. The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee. The guarantee requires no liability to be recorded, contains no recourse provisions and requires no collateral. On Dec. 31, 2008, NSP-Wisconsin had the following guarantee and exposure related to that guarantee:

Table of Contents

Nature of Guarantee
(Millions of Dollars)

Guarantee
Amount

Current
Exposure

Term or
Expiration
Date

Triggering
Event
Requiring
Performance

Assets
Held as
Collateral

Guarantee of customer loans for the Farm Rewiring Program

1.0

0.3

Continuing

(a)

N/A

(a)

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

Letters of Credit

NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2008 and 2007, there were no letters of credit outstanding.

11. Fair Value Measurements

Effective Jan. 1, 2008, NSP-Wisconsin adopted SFAS No. 157 for recurring fair value measurements. SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

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

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

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

NSP-Wisconsin held several commodity derivatives measured at fair value on a recurring basis as of Dec. 31, 2008. Fair value for these commodity derivatives was determined based on observable prices for identical or similar forward contracts, or internally prepared option valuation models using observable forward curves and volatilities. NSP-Wisconsin continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well an assessment of the impact of NSP-Wisconsin’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities at Dec. 31, 2008.

The following table presents, for each of the SFAS No. 157 hierarchy levels, NSP-Wisconsin’s assets and liabilities that are measured at fair value on a recurring basis as of Dec. 31, 2008:

(Thousands of Dollars)	Level 1		Level 2		Level 3		Counterparty Netting (a)		Net Balance
Commodity derivative assets (b)	$	—	$	2	$	—	$	—	$	2
Commodity derivative liabilities	600		1,269		—		—		1,869

(a) FASB Interpretation No. 39 Offsetting of Amounts Relating to Certain Contracts, as amended by FASB Staff Position FIN 39-1 Amendment of FASB Interpretation No. 39, permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Wisconsin and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

(b) Amounts included in prepayments and other in the consolidated balance sheets.

Table of Contents

12. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — PSCW

Base Rate

Electric and Gas 2008 Rate Case — In January 2008, the PSCW issued the final written order in NSP-Wisconsin’s 2008 test year rate case, approving an electric rate increase of approximately $39.4 million, or 8.1 percent, and a natural gas rate increase of $5.3 million, or 3.3 percent. The rate increase was based on a 10.75 percent ROE and a 52.5 percent common equity ratio. New rates went into effect in January 2008.

Electric Limited Reopener 2009 Rate Case — On Aug. 1, 2008, NSP-Wisconsin filed an application with the PSCW requesting authority to increase retail electric rates by $47.1 million, which represented an overall increase of 8.6 percent. In the application, NSP-Wisconsin requested the PSCW to reopen the 2008 base rate case for the limited purpose of adjusting 2009 electric rates to reflect forecasted increases in production and transmission costs, as authorized by the PSCW. No changes were requested to the capital structure or return on equity authorized by the PSCW in the 2008 base rate case.

NSP-Wisconsin and the intervenors entered into a stipulated agreement and on Dec. 30, 2008, the PSCW issued an order approving the stipulation and authorizing a $5.6 million rate increase. The original request of $47.1 million was reduced by $31.6 million due to the decline in market prices for fuel and purchased power, $5.5 million for a change in nuclear outage accounting and $4.4 million due to other adjustments.

Further, in accordance with the stipulation agreement, an estimated 2008 interim fuel surcharge refund liability of $9.8 million, recorded in 2008, will be offset by the $5.6 million 2009 rate increase, and the remaining liability will be refunded to customers in 2009, after the PSCW completes its final review of 2008 actual fuel costs.

Electric, Purchased Gas and Resource Adjustment Clauses

MISO ASM Cost Recovery — In the Dec. 30, 2008 order in NSP-Wisconsin’s 2009 electric rate case, the PSCW included the costs and benefits associated with the MISO ASM in the fuel monitoring range established for 2009. Accordingly, ASM costs will flow through NSP-Wisconsin’s fuel cost recovery mechanism in a similar fashion as all other fuel and purchased power costs. On Jan. 6, 2009, MISO began ASM operations.

Other

Nuclear Refueling Outage Costs — On Sept. 16, 2008, the MPUC approved NSP-Minnesota’s request to adopt the deferral-and-amortization method of accounting for costs associated with refueling outages at its nuclear plants, effective Jan. 1, 2008. NSP-Wisconsin’s 2008 Wisconsin retail electric retail rates were set based on the previous direct-expense accounting method, and recovered costs associated with 2008 refueling outages in 2008. For ratemaking purposes, NSP-Wisconsin switched to the deferral and amortization method effective Jan. 1, 2009. To reflect timing differences between when the revenue was received from customers versus when the corresponding expense will be billed through the interchange agreement, NSP-Wisconsin recorded a liability of $4.8 million. The liability will be fully amortized by the end of 2010.

2008 Electric Fuel Cost Recovery — On May 2, 2008, the PSCW approved, on an interim basis, NSP-Wisconsin’s request of a $19.7 million surcharge, or 3.8 percent, on an annual basis, to recover forecast increases in fuel and purchased power costs. The interim fuel surcharge was in effect from May 6, 2008 to Dec. 31, 2008, and generated approximately $12.7 million in additional revenue in 2008. The revenues that NSP-Wisconsin collected were subject to refund with interest at a rate of 10.75 percent, pending PSCW review and final approval. The PSCW will conduct its final review of the interim fuel surcharge in 2009, after 2008 actual fuel costs are known.

NSP-Wisconsin actual retail fuel costs in 2008 were approximately $14.8 million less than assumed in the April 2008 forecast used to set the interim fuel surcharge, primarily due to lower market prices for fuel and purchased power. Based on actual fuel costs for 2008, NSP-Wisconsin has established a liability of $9.8 million to reflect the expected refund of interim surcharge revenues that will be determined by the PSCW. Notwithstanding the interim surcharge and lower than forecast fuel costs, NSP-Wisconsin’s 2008 calendar year fuel costs exceeded authorized revenues by approximately $1.7 million, net of the anticipated refund.

In accordance with the stipulation agreement approved by the PSCW in NSP-Wisconsin’s 2009 limited electric rate case, the estimated 2008 interim fuel surcharge refund liability of $9.8 million will be offset by the $5.6 million 2009 rate increase,

Table of Contents

and the remaining liability will be refunded to customers in 2009, after the PSCW completes its final review of 2008 actual fuel costs.

Fuel Cost Recovery Rulemaking — In June 2006, the PSCW opened a rulemaking docket to address potential revisions to the electric fuel cost recovery rules. Wisconsin statutes prohibit the use of automatic adjustment clauses by large investor-owned electric public utilities. The statutes authorize the PSCW to approve a rate increase for these utilities to allow for the recovery of costs caused by an emergency or extraordinary increase in the cost of fuel.

In August 2007, the PSCW staff issued its draft revisions to the fuel rules and requested comments. The proposed rules incorporate a plan year fuel cost forecast, deferred accounting for differences between actual and forecast costs if the difference is greater than 2 percent, and an after-the-fact reconciliation proceeding to allow the opportunity to recover or refund the deferred balance.

On July 3, 2008, the PSCW issued its notice of hearing in the rulemaking and requested public comments on the proposed revisions to the fuel rules. The proposed revisions to the rules were substantively the same as the version issued in August 2007, described above. A public hearing was held Aug. 4, 2008, and written comments were filed by the parties on Aug. 6, 2008. The utilities subject to the fuel rules, including NSP-Wisconsin, the Wisconsin Utilities Association, and Wisconsin Utility Investors, Inc. filed comments generally supporting the revised rules. An ad hoc coalition of intervenors, consisting of consumer and industrial customer groups, filed joint comments in opposition to the proposed rules.

The PSCW did not forward the proposed rules to the legislature for approval before the statutory deadline for action in the 2007-08 legislative session. At this time it is uncertain what, if any, additional action the PSCW will take with respect to this rulemaking, or the fuel rules in general.

Bay Front Emission Controls Certificate of Authority — In March 2008, the PSCW issued a certificate of authority and order approving NSP-Wisconsin’s application to install equipment relating to combustion improvement and NOx emission controls in boilers 1 and 2 at the Bay Front power plant in Ashland, Wis. Construction began in May and was completed in the fourth quarter of 2008. The new equipment and systems are in the testing and tuning phase, which is expected to be completed in the first quarter of 2009.

13. Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2008, the estimated cost of the capital expenditure programs and other capital requirements of NSP-Wisconsin is approximately $100 million in 2009, $115 million in 2010 and $135 million in 2011. NSP-Wisconsin’s capital forecast includes the following major project:

CAPX 2020 — In June 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified several groups of transmission projects that proposed to be complete by 2020. Group 1 project investments are expected to total approximately $1.7 billion, with major construction targeted to begin in 2010 and ending three to five years later. Xcel Energy’s investment is expected to be approximately $900 million depending on the route and configuration approved by the MPUC. Approximately 75 percent of the capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota TCR tariff rider mechanism authorized by Minnesota legislation, as well as a similar TCR mechanism passed in South Dakota. Cost recovery by NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.

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

Fuel Contracts — NSP-Wisconsin has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2009 and 2027. In addition, NSP-Wisconsin may be required to pay additional amounts depending on actual quantities shipped under these agreements. As NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers, NSP-Wisconsin may seek deferred accounting treatment and future rate recovery of increased costs due to an emergency event, if that event causes fuel costs to exceed the amount included in rates on an annual basis by more than 2 percent.

Table of Contents

The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2008, is as follows:

Coal		Natural Gas Supply		Gas Storage & Transportation
(Millions of Dollars)
$	17	$	16	$	108

Leases — NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases. Rental expense under operating lease obligations was approximately $2.1 million, $3.1 million and $2.6 million for 2008, 2007 and 2006, respectively. The majority of rental expense is for one-year renewable leases.

Future commitments under operating leases are:

(Millions of Dollars)
2009	$	0.7
2010	0.7
2011	0.6
2012	0.4
2013	0.4
Thereafter	0.9

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

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is legally limited to $12.5 billion. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $117.5 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $17.5 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs with coverage limits of $2.2 billion for each of NSP-Minnesota’s two nuclear plant sites. The insurance also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term, subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the insurance reserve funds to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $29.7 million for property damage insurance if losses exceed accumulated reserve funds.

Environmental Contingencies

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

Table of Contents

Site Remediation — NSP-Wisconsin must pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin or other parties have caused environmental contamination. Environmental contingencies could arise from various situations including sites of former MGPs operated by NSP-Wisconsin, its predecessors, or other entities; and third party sites, such as landfills, to which NSP-Wisconsin is alleged to be a PRP that sent hazardous materials and wastes. At Dec. 31, 2008, the liability for the cost of remediating these sites was estimated to be $69.0 million, of which $1.0 million was considered to be a current liability.

Manufactured Gas Plant Sites

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

In September 2002, the Ashland site was placed on the National Priorities List. A final determination of the scope and cost of the remediation of the Ashland site is not currently expected until early 2009. In October 2004, the state of Wisconsin filed a lawsuit in Wisconsin state court for reimbursement of past oversight costs incurred at the Ashland site between 1994 and March 2003 in the approximate amount of $1.4 million. The state also alleges a claim for forfeitures and interest. All costs paid to the state are expected to be recoverable in rates.

In November 2005, the EPA Superfund Innovative Technology Evaluation Program (SITE) Program accepted the Ashland site into its program. As part of the SITE program, NSP-Wisconsin proposed and the EPA accepted a site demonstration of an in situ, chemical oxidation technique to treat upland ground water and contaminated soil. The fieldwork for the demonstration study was completed in February 2007. In 2008, NSP-Wisconsin spent $0.8 million in the development of the work plan, the operation of the existing interim response action and other matters related to the site. In June 2007, the EPA modified its remedial investigation report to establish final remedial action objectives (RAOs) and preliminary remediation goals (PRGs) for the Ashland site. The RAOs and PRGs could potentially impact the development and evaluation of remedial options for ultimate site cleanup.

In October 2007, the EPA approved the series of reports included in the remedial investigation report. On Dec. 4, 2008, the EPA approved the final feasibility study submitted by NSP-Wisconsin. The final feasibility study sets forth a range of remedial options under consideration by the EPA for the site but does not select a remedy. The EPA Remedy Review Board met in November 2008 to consider the remedial approach proposed by the Remedial Project Manager (RPM) for EPA Region 5. The remedy the EPA will suggest for the site, following input from the EPA Remedy Review Board, will be set forth in its Proposed Plan which is currently expected in early 2009. The Proposed Plan will undergo public comment before the EPA makes its final remedy selection in its record of decision, which is currently expected to be issued in late 2009. The estimated remediation costs for the site range between $49.7 million and $137.5 million, including costs set forth in the revised feasibility study, as well as estimates for WDNR past oversight costs, outside legal and consultant costs and work plan costs.

In addition to potential liability for remediation, NSP-Wisconsin may also have liability for natural resource damages (NRD) at the Ashland site. NSP-Wisconsin has indicated to the relevant natural resource trustees its interest in engaging in discussions concerning the assessment of natural resources injuries and in proposing various restoration projects in an effort to fully and finally resolve all NRD claims. NSP-Wisconsin is not able to accurately quantify its potential exposure for NRD at the site, but has recorded an estimate of its potential liability based upon its best estimate of potential exposure.

Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the actual cost of remediating the Ashland site and the time frame over which the amounts may be paid out are not determinable. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site. NSP-Wisconsin has recorded a liability of $65.9 million based on management’s best estimate of remediation costs. NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for MGP-related environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.

Table of Contents

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

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. NSP-Wisconsin’s removal costs for asbestos are expected to be immaterial; therefore, no asset retirement obligation was recorded. See additional discussion of asset retirement obligations below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

CAIR — In March 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The objective of CAIR was to cap emissions of SO2 and NOx in the eastern United States, including Wisconsin. In July 2008, the D.C. Circuit Court of Appeals vacated CAIR and remanded the rule to EPA. On Dec. 23, 2008, the court reinstated CAIR while the EPA develops new regulations in accordance with the court’s July opinion.

As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

Purchases of NOx allowances for NSP-Wisconsin are estimated at $2.1 million in 2009. NSP-Wisconsin believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

CAMR — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the D. C. Circuit Court of Appeals vacated CAMR, which impacts federal CAMR requirements but not necessarily state-only rules.

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

NSP-Wisconsin has proposed a gasifier project for boiler 5. If the gasifier project is implemented prior to 2015, that boiler will no longer be subject to this rule as long as the modification does not increase mercury emissions, and the boiler no longer burns coal. At that point, it will likely be subject to revised commercial and industrial boiler Maximum Achievable Control Technology (Boiler MACT) requirements. In addition, if the Boiler MACT is revised prior to 2015, boilers 1 and 2 will no longer be subject to this rule, and will need to comply with the Boiler MACT. As such, any cost estimates to comply with the Wisconsin mercury reduction rule are premature at this time.

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking. In January 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration. In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the court-ordered remand. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. In April 2008, the U.S. Supreme Court granted limited review of the Second Circuit’s opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA. A decision is not expected until 2009.

Table of Contents

Asset Retirement Obligations

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

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

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Wisconsin’s AROs is shown in the table below for the 12 months ended Dec. 31, 2008 and Dec. 31, 2007, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2008		Liabilities Recorded		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2008

Electric Utility Plant:
Electric transmission and distribution	$	24	$	—	$	—	$	1	$	4		$	29
Gas Utility Plant:
Gas transmission and distribution	2,878		—				72		(2,894		)	56
Total liability	$	2,902	$	—	$	—	$	73	$	(2,890	)	$	85

NSP-Wisconsin revised gas distribution and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2007		Liabilities Recorded		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2007

Electric Utility Plant:
Electric transmission and distribution	$	180	$	—	$	—	$	4	$	(160	)	$	24
Gas Utility Plant:
Gas transmission and distribution	2,809		—		—		69		—			2,878
Total liability	$	2,989	$	—	$	—	$	73	$	(160	)	$	2,902

Removal Costs — NSP-Wisconsin accrues an obligation for plant removal costs for generation, transmission and distribution facilities. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2008 and Dec. 31, 2007 were $96 million and $94 million, respectively.

Table of Contents

Legal Contingencies

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

Gas Trading Litigation

Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al. — e prime was a subsidiary of Xcel Energy Markets Holdings Inc., which is a wholly owned subsidiary of Xcel Energy. Among other things, e prime was in the business of natural gas trading and marketing. e prime has not engaged in natural gas trading or marketing activities since 2003. In February 2007, a complaint was filed alleging that NSP-Wisconsin, Xcel Energy and e prime, among others, engaged in fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The plaintiffs seek a declaration that contracts for natural gas entered into between Jan. 1, 2000 and Oct. 31, 2002 are void, that they are entitled to repayment for amounts paid for natural gas during that time period, and that treble damages are appropriate. The case was filed in the Wisconsin State Court (Dane County), and then removed to U.S. District Court for the Western District of Wisconsin. In June 2007, the plaintiffs filed a motion to remand the matter to state court, which was denied, and the matter was transferred by the Multi-District Litigation panel to Federal District Court Judge Pro in Nevada, who is the judge assigned to the Western Area Wholesale Natural Gas Antitrust Litigation. In July 2007, plaintiffs filed an amended complaint in Federal District Court in Nevada, which includes allegations against NRG, a former Xcel Energy subsidiary. This gas-trading lawsuit is in the early procedural stages of litigation. In February 2008, the court denied the defendants’ motions for summary judgment, granted plaintiffs’ motion to conduct limited discovery, and stated that defendants may renew their summary judgment motions upon completion of discovery.

Environmental Litigation

Carbon Dioxide Emissions Lawsuit — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit. In June 2007 the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by the EPA under the CAA. In July 2007, in response to the request of the Court of Appeals, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. Oral arguments were presented to the Court of Appeals on Aug. 6, 2008. Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008. No explanation was given for the order. The Court of Appeals has taken the matter under advisement.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of NSP-Wisconsin, and 23 other utilities, oil, gas and coal companies. The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that Defendants’ emission of CO2 and other greenhouse gases contribute to global

Table of Contents

warming, which is harming their village. Plaintiffs claim that as a consequence, the entire village must be relocated at a cost of between $95 million and $400 million. Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other. Xcel Energy was not named in the civil conspiracy claim. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on Sept. 30, 2008. The matter has now been fully briefed, with oral arguments set for May 19, 2009. It is unknown when the court will render a decision.

Employment, Tort and Commercial Litigation

MGP Insurance Coverage Litigation — In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire and LaCrosse, Wis. In lieu of participating in discussions, in October 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state court. In November 2003, NSP-Wisconsin commenced suit in Wisconsin state court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation. The Wisconsin action remains in abeyance.

NSP-Wisconsin has reached settlements with 22 insurers, and these insurers have been dismissed from both the Minnesota and Wisconsin actions.

In July 2007, the Minnesota state court issued a decision on allocation, reaffirming its prior rulings that Minnesota law on allocation should apply and ordering the dismissal, without prejudice, of eleven insurers whose coverage would not be triggered under such an allocation method. In September 2007, NSP-Wisconsin commenced an appeal in the Minnesota Court of Appeals challenging the dismissal of these carriers. In November 2007, Ranger Insurance Company (Ranger) and TIG Insurance Company (TIG) filed a motion to dismiss NSP-Wisconsin’s appeal, asserting that NSP-Wisconsin’s failure to serve Continental Insurance Company, as successor in interest to certain policies issued by Harbor Insurance Company (Harbor), requires dismissal of NSP-Wisconsin’s appeal. In February 2008, the Court of Appeals issued an order deferring a decision on the procedural motion filed by Harbor and TIG and referring the motion to the panel assigned to consider the merits of the appeal.

In April 2008, the Court of Appeals issued an order staying briefing and other appellate proceedings until further order of the court. The order was issued in response to NSP-Wisconsin’s request that oral argument be deferred pending a decision by the Wisconsin Supreme Court in Plastics Engineering Co. vs. Liberty Mutual Insurance Co. On Jan. 29, 2009, the Wisconsin Supreme Court issued its decision in Plastics Engineering Co., adopting an all sums method of allocating damages when an injury spans multiple, successive policy periods. On Feb. 3, 2009, the Court of Appeals issued an order dissolving the stay and establishing a briefing schedule. NSP-Wisconsin has until March 9, 2009 to file a supplemental brief addressing the impact of Plastics Engineering Co. The insurers have until April 9, 2009 to file their initial briefs on appeal. Thereafter, NSP-Wisconsin will reply to the insurers’ briefs.

The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers. None of the aforementioned lawsuit settlements are expected to have a material effect on Xcel Energy’s consolidated financial statements.

Stray Voltage — In November 2001, Ralph and Karline Schmidt filed a complaint against NSP-Wisconsin alleging that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and seek compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.1 million and pre-verdict interest of $2.5 million. In addition, plaintiffs allege an unspecified amount of damages related to nuisance. The matter was resolved on a confidential basis during mediation on Jan. 7, 2009. The settlement will not have a material effect on the consolidated financial statements of NSP-Wisconsin.

In November 2001, August C. Heeg Jr. and Joanne Heeg filed a complaint against NSP-Wisconsin alleging that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and seek compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.9 million and pre-verdict interest of $6.1 million. In addition, plaintiffs allege an unspecified amount of damages related to nuisance. The matter was resolved on a confidential basis during mediation on Dec. 1, 2008 and the case was dismissed. The settlement will not have a material effect on NSP-Wisconsin.

Table of Contents

14. Regulatory Assets and Liabilities

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

(Thousands of Dollars)	See Note	Remaining Amortization Period	2008		2007
Regulatory Assets
Pension and employee benefit obligations	1	Various	$	86,595	$	32,217
Environmental costs	1	Varies, generally four to six years once actual expenditures are incurred	63,727		38,427
Losses on reacquired debt		Term of related debt	8,787		9,751
Nuclear decommissioning costs (a) (c)		To be determined in future rate proceedings	8,775		11,149
AFDC recorded in plant (a)		Plant lives	8,619		8,484
State commission accounting adjustments (a)		Plant lives	3,882		3,950
MISO Day 2 costs (a)		Generally one year	3,041		6,209
Contract valuation adjustments (b)		Term of related contract	2,884		1,581
Conservation programs		Various	711		1,564
Other		Various	2,732		1,041
Total noncurrent regulatory assets			$	189,753	$	114,373

(Thousands of Dollars)	See Note	Remaining Amortization Period	2008		2007
Regulatory Liabilities
Plant removal costs	13		$	96,745	$	94,224
Investment tax credit deferrals			6,939		7,316
Gain on sale of emission allowances			333		417
Wisconsin overrecovered fuel costs			76		149
Other			1,205		1,221
Total noncurrent regulatory liabilities			$	105,298	$	103,327

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

(b) Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements.

(c) Approximately $2.9 million will be recovered during 2009. The remaining amount will be determined in a future rate proceeding.

15. Segments and Related Information

NSP-Wisconsin has two reportable segments, regulated electric utility and regulated natural gas utility.

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

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

Table of Contents

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include investments in rental housing projects that qualify for low-income housing tax credits.

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of NSP-Wisconsin.

To report net income for regulated electric and regulated natural gas utility segments, NSP-Wisconsin must assign or allocate all costs and certain other income. In general, costs are:

· Directly assigned wherever applicable;

· Allocated based on cost causation allocators wherever applicable; or

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

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2008
Operating revenues from external customers	$	665,375	$	179,434	$	910		$	—		$	845,719
Intersegment revenues	181		1,829		—			(2,010		)	—
Total revenues	$	665,556	$	181,263	$	910		$	(2,010	)	$	845,719
Depreciation and amortization	$	49,727	$	8,432	$	176		$	—		$	58,335
Interest charges and financing costs	20,611		2,796		1,181			—			24,588
Income tax expense (benefit)	24,287		4,390		(903		)	—			27,774
Net income (loss)	$	39,305	$	6,502	$	(286	)	$	—		$	45,521

2007
Operating revenues from external customers	$	631,833	$	148,841	$	843		$	—		$	781,517
Intersegment revenues	162		390		—			(552		)	—
Total revenues	$	631,995	$	149,231	$	843		$	(552	)	$	781,517
Depreciation and amortization	$	46,869	$	7,089	$	162		$	—		$	54,120
Interest charges and financing costs	17,967		2,385		1,191			—			21,543
Income tax expense (benefit)	20,272		2,734		(888		)	—			22,118
Net income (loss)	$	33,741	$	4,144	$	(19	)	$	—		$	37,866

2006
Operating revenues from external customers	$	585,049	$	149,242	$	782		$	—		$	735,073
Intersegment revenues	123		3,277		—			(3,400		)	—
Total revenues	$	585,172	$	152,519	$	782		$	(3,400	)	$	735,073
Depreciation and amortization	$	44,979	$	6,711	$	162		$	—		$	51,852
Interest charges and financing costs	18,255		2,411		1,295			—			21,961
Income tax expense (benefit)	23,541		1,590		(663		)	—			24,468
Net income (loss)	$	41,772	$	2,440	$	(538	)	$	—		$	43,674

Table of Contents

16. Related Party Transactions

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

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

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

(Thousands of Dollars)	2008		2007		2006
Operating revenues:
Electric utility	$	106,363	$	120,217	$	99,403
Operating expenses:
Purchased power	357,946		344,501		298,208
Transmission expense	32,197		27,714		24,525
Natural gas purchased for resale	312		366		350
Other operations — paid to Xcel Energy Services Inc.	45,819		45,441		48,895
Interest expense	1,064		1,081		1,187

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

	2008				2007
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	—	$	12,416	$	—	$	20,918
PSCo	—		71		2		—
SPS	—		58		—		87
Other subsidiaries of Xcel Energy	599		5,055		2,716		4,686
	$	599	$	17,600	$	2,718	$	25,691

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements. At Dec. 31, 2008 and 2007, NSP-Wisconsin had notes payable outstanding to NSP-Minnesota in the amount of $0.0 million and $58.6 million, respectively.

Clearwater Investments Inc., an NSP-Wisconsin subsidiary, also had notes payable outstanding as of Dec. 31, 2008 and 2007 to Xcel Energy, in the amount of $0.7 million.

17. Summarized Quarterly Financial Data (Unaudited)

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

	Quarter Ended
(Thousands of Dollars)	March 31, 2008		June 30, 2008		Sept. 30, 2008		Dec. 31, 2008

Operating revenues	$	244,239	$	188,139	$	192,005	$	221,336
Operating income	25,898		14,716		25,253		30,801
Net income	13,140		5,991		11,091		15,299

	Quarter Ended
(Thousands of Dollars)	March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007

Operating revenues	$	212,295	$	175,176	$	188,734	$	205,312
Operating income	19,822		13,002		32,376		13,611
Net income	9,129		5,299		16,650		6,788

Table of Contents

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

During 2007 and 2008, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Wisconsin on accounting principles or practices, financial statement disclosures or audit scope or procedures.

Item 9A(T) — Controls and Procedures

Disclosure Controls and Procedures

NSP-Wisconsin maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2008, based on an evaluation carried out under the supervision and with the participation of NSP-Wisconsin’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Wisconsin’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Wisconsin’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Wisconsin’s internal control over financial reporting. NSP-Wisconsin maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Wisconsin has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2008 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Wisconsin conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Wisconsin did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

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

Item 9B — Other Information

None

PART III

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

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

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

Item 13 — Certain Relationships, Related Transactions and Director Independence

Item 14 — Principal Accounting Fees and Services

Table of Contents

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2009 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules

1.		Consolidated Financial Statements
		Management Report on Internal Controls — For the year ended Dec. 31, 2008.
		Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2008, 2007 and 2006.
		Consolidated Statements of Income — For the three years ended Dec. 31, 2008, 2007 and 2006.
		Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2008, 2007 and 2006.
		Consolidated Balance Sheets — As of Dec. 31, 2008 and 2007.

2.		Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2008, 2007 and 2006.

3.		Exhibits

3.01*		Amended and restated articles of incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) Jan. 21, 2004).

3.02*		By-Laws of NSP-Wisconsin as amended Dec. 6, 2001 (Exhibit 3.02 to Form S-4 (file no. 333-112033) Jan. 21, 2004).

3.03*		By-Laws of Northern States Power Company, a Wisconsin corporation, as amended Dec. 6, 2001 and June 3, 2008, (Exhibit 3.02 to Form 10-Q (file no. 001-03140) Aug. 4, 2008).

4.01*		Supplemental and Restated Trust Indenture dated March 1, 1991. (Exhibit 4.01K to Registration Statement 33-39831).

4.02*		Supplemental Trust Indenture dated April 1, 1991. (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).

4.03*		Supplemental Trust Indenture dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).

4.04*		Trust Indenture dated Sept. 1, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).

4.05*		Supplemental Trust Indenture dated Sept. 1, 2003 between Northern States Power Co. (a Wisconsin corporation) and US Bank N.A., supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).

4.06*		Supplemental Trust Indenture dated as of Sept. 1, 2008 between Northern States Power Company (Wisconsin) and U.S. Bank National Association, as successor Trustee, creating $200,000,000 principal amount of 6.375% First Mortgage Bonds, Series due Sept. 1, 2038 (Exhibit 4.01 of Form 8-K of Northern States Power Company, a Wisconsin corporation, dated Sept. 3, 2008 (file no. 001-03140)).

10.01*+		Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).

10.02*+		Xcel Energy Inc. Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

10.03*+		Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).

10.04*+		New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).

10.05*+		Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008)

Table of Contents

10.06*+		Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.

10.07*+		Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

10.08*+		Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

10.09*+		Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).

10.10*+		Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).

10.11*+		Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).

10.12*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).

10.13*+		Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).

10.14*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).

10.15*+		Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).

10.16*+		Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).

10.17*+		Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

10.18*+		Agreement, dated March 20, 2007 between Mr. Gary R. Johnson and Xcel Energy Inc. (Exhibit 10.1 to Form 8-K (file no. 001-03034) dated March 20, 2007).

10.19*+		Letter dated Sept. 19, 2007, from Xcel Energy Inc. to the U.S. Department of Justice (DOJ) submitting its offer to settle the COLI tax dispute and Letter dated Sept. 21, 2007 from the DOJ to Xcel Energy Inc. accepting the settlement offer. (Exhibit 10.1 to Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2007).

10.20*+		Amendment Four to Employment Agreement between Xcel Energy Inc. and Paul Bonavia (Exhibit 10.02 to Xcel Energy’s Form 8-K (file no. 001-03034) dated May 23, 2007).

10.21*+		First Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

10.22*+		First Amendment to the Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009 (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

10.23*		Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).

12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.

23.01		Consent of Independent Registered Public Accounting Firm.

Table of Contents

SCHEDULE II

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2008, 2007 and 2006

(amounts in thousands of dollars)

			Additions
	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts (1)		Deductions from reserves (2)		Balance at end of period
Reserve deducted from related assets:
Allowance for bad debts:
2008	$	2,830	$	4,784	$	1,135	$	4,091	$	4,658
2007	2,180		4,235		1,389		4,974		2,830
2006	1,461		5,984		1,374		6,639		2,180

(1) Recovery of amounts previously written off

(2) Principally bad debts written off or transferred

/S/ MICHAEL L. SWENSON		/S/ BENJAMIN G.S. FOWKE III
Michael L. Swenson		Benjamin G.S. Fowke III
President and Chief Executive Officer		Executive Vice President and Chief Financial Officer
February 27, 2009		February 27, 2009

FORM 10-K

NORTHERN STATES POWER COMPANY

1414 West Hamilton Avenue, Eau Claire, Wisconsin 54701

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Overview

Public Utility Regulation

Summary of Recent Federal Regulatory Developments

NATURAL GAS UTILITY OPERATIONS

Public Utility Regulation

Natural Gas Operating Statistics

ENVIRONMENTAL MATTERS

EMPLOYEES

Additional Information

Electric Revenues and Margin

CONSOLIDATED STATEMENTS OF INCOME

Pension Benefits

Defined Contribution Plans

Postretirement Health Care Benefits

Projected Benefit Payments

Types of and Accounting for Derivative Instruments

Cash Flow Hedges

Base Rate

Third Party and Other Environmental Site Remediation

Other Environmental Requirements

Legal Contingencies

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

STATEMENT OF COMPUTATION OF

CERTIFICATION

CERTIFICATION

PART I
Item 1 — Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Overview
Public Utility Regulation
Capacity and Demand
Energy Sources and Related Transmission Initiatives
Fuel Supply and Costs
Fuel Sources
Summary of Recent Federal Regulatory Developments
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Public Utility Regulation
Capability and Demand
Natural Gas Supply and Costs
Natural Gas Operating Statistics
ENVIRONMENTAL MATTERS
EMPLOYEES
Item 1A — Risk Factors
Item 1B — Unresolved SEC Staff Comments
Item 2 — Properties
Item 3 — Legal Proceedings
Item 4 — Submission of Matters to a Vote of Security Holders

PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6 — Selected Financial Data
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Item 8 — Financial Statements and Supplementary Data
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A(T) — Controls and Procedures
Item 9B — Other Information

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

PART IV
Item 15 — Exhibits, Financial Statement Schedules

SIGNATURES

/S/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 27, 2009

31.01		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.02		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

	NORTHERN STATES POWER COMPANY

	/S/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

February 27, 2009

/S/ MICHAEL L. SWENSON		/S/ RICHARD C. KELLY
Michael L. Swenson		Richard C. Kelly
President, Chief Executive Officer and Director		Chairman and Director
(Principal Executive Officer)

/S/ TERESA S. MADDEN		/S/ BENJAMIN G.S. FOWKE III
Teresa S. Madden		Benjamin G.S. Fowke III
Vice President and Controller		Executive Vice President, Chief Financial Officer and Director
(Principal Accounting Officer)		(Principal Financial Officer)

	/S/ MICHAEL L. SWENSON
	Michael L. Swenson
	President and Chief Executive Officer

Date: February 27, 2009