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, 2012

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 incorporation or organization)	(I.R.S. Employer Identification No.)

1414 West Hamilton Avenue

Eau Claire, Wisconsin 54701

(Address of principal executive offices)

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x 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. 25, 2013, 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 2013 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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

TABLE OF CONTENTS

Index

PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	7
Fuel Sources	7
Renewable Energy Sources	8
Summary of Recent Federal Regulatory Developments	9
Electric Operating Statistics	10
NATURAL GAS UTILITY OPERATIONS	11
Public Utility Regulation	11
Capability and Demand	12
Natural Gas Supply and Costs	12
Natural Gas Operating Statistics	13
GENERAL	13
ENVIRONMENTAL MATTERS	14
EMPLOYEES	14
Item 1A — Risk Factors	14
Item 1B — Unresolved Staff Comments	23
Item 2 — Properties	24
Item 3 — Legal Proceedings	24
Item 4 — Mine Safety Disclosures	24
PART II	24
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6 — Selected Financial Data	25
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	28
Item 8 — Financial Statements and Supplementary Data	28
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	67
Item 9A — Controls and Procedures	68
Item 9B — Other Information	68
PART III	68
Item 10 — Directors, Executive Officers and Corporate Governance	68
Item 11 — Executive Compensation	68
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	68
Item 13 — Certain Relationships and Related Transactions, and Director Independence	68
Item 14 — Principal Accountant Fees and Services	68
PART IV	69
Item 15 — Exhibits, Financial Statement Schedules	69
SIGNATURES	72

This Form 10-K is filed by NSP-Wisconsin.  NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC.  This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The integrated electric production and transmission system of NSP-Minnesota and NSP-Wisconsin managed by NSP-Minnesota
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
FCA	Fuel clause adjustment
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
APBO	Accumulated postretirement benefit obligation
ARC	Aggregator of Retail Customers
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CO2	Carbon dioxide
CPCN	Certificate of public convenience and necessity
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG IFRS	Greenhouse gas International Financial Reporting Standards
LNG	Liquefied natural gas
MACT	Maximum Achievable Control Technology
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services, Inc.

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MVP	Multi-Value Project
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NOL	Net operating loss
NOx	Nitrogen oxide
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
REC	Renewable energy credit
ROE	Return on equity
RPS	Renewable portfolio standards
RSG	Revenue sufficiency guarantee
RTO	Regional Transmission Organization
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services
Measurements
KV	Kilovolts
KWh	Kilowatt hours
Mcf	Thousand cubic feet
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin.  NSP-Wisconsin is an operating utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan.  The wholesale customers served by NSP-Wisconsin comprised approximately 6 percent of its total KWh sold in 2012.  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 251,000 customers and natural gas utility service to approximately 108,000 customers.  Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2012.  Although NSP-Wisconsin’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large commercial and industrial electric sales include customers in the following industries:  paper and allied products, food products, as well as oil and gas extraction.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries:  grocery and dining establishments and educational services.  Generally, NSP-Wisconsin’s earnings contribute approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

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.  See Note 13 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.

NSP-Wisconsin’s corporate strategy focuses on three core objectives: obtain stakeholder alignment; invest in our regulated utility businesses; and earn a fair return on our utility investments.  NSP-Wisconsin files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.  Environmental leadership is a core priority for NSP-Wisconsin and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

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

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

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW for approval.  Once the PSCW approves the fuel cost plan, utilities defer the amount of any fuel cost over-collection or under-collection in excess of a two percent annual tolerance band, for future rate recovery or refund.  Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW after an opportunity for a hearing.  Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE.

NSP-Wisconsin’s wholesale electric rate schedules include a FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.  Effective Jan. 1, 2013, NSP-Wisconsin no longer serves any wholesale municipal electric customers.  Rates for wholesale municipal services provided in 2012 will be subject to a formula rate true-up in 2013.

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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.

Wisconsin Energy Efficiency and Conservation Goals — In June 2011, the Wisconsin biennial budget bill was signed into law, which rolled back the projected increases for state energy efficiency and conservation funding effective in 2012.  Based on this action, NSP-Wisconsin was allocated approximately $8.1 million of the statewide program costs in 2012.  This amount is expected to increase to approximately $8.6 million by 2014.  Historically, NSP-Wisconsin has recovered these costs in rates charged to Wisconsin retail customers and expects to recover the program costs in rates going forward.

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 2013, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2010		2011		2012		2013 Forecast
NSP System		9,131		9,792		9,475		9,215

The peak demand for the NSP System typically occurs in the summer.  The 2012 uninterrupted system peak demand for the NSP System occurred on July 2, 2012.  The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted system peak demand since July 31, 2006.   The 2012 peak demand occurred uninterrupted on a day with weather much closer to normal peak day conditions.  The forecast for 2013 assumes normal peak day weather and includes the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin.  The 2013 forecast also reflects the impact of two large commercial and industrial customers that have ceased operations.  These customers represented 0.05 percent of 2012 sales.

Energy Sources and Related Transmission Initiatives

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

Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased.  NSP-Minnesota also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.

Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Wisconsin and NSP-Minnesota have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.

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

In November 2012, the MPUC issued an order on NSP-Minnesota’s resource plan and required additional filings to determine the next resources needed for the NSP System generating capacity.  In December 2012, NSP-Minnesota filed its information indicating an estimated need of 150 MW in 2017 and increasing to 440 MW by 2019, with the size and timing to be determined by the MPUC.  A competitive acquisition process is anticipated to commence in March 2013 and result in the selection of a developer or developers by the MPUC in the fourth quarter of 2013.

NSP-WisconsinCapX2020 CPCN — The PSCW issued a CPCN for the Wisconsin portion of the CapX2020 Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV project in May 2012.  The Wisconsin portion consists of approximately 50 miles of new transmission line.  The PSCW also approved a route permit and the cost is estimated at $211 million.  Subsequent legal challenges to the PSCW’s order by intervenors were unsuccessful, thereby rendering the PSCW’s order final.  Construction on the Wisconsin portion of the line is anticipated to begin in 2014 and the line is expected to go into service in 2015.

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Fuel Supply and Costs

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

	Coal*				Nuclear					Natural Gas				Weighted Average Owned
NSP System Generating Plants	Cost		Percent		Cost			Percent		Cost		Percent		Fuel Cost
2012	$	2.13	47	%		$	0.90	42	%	$	4.21	11	%	$	1.88
2011		2.06	55				0.89	40			6.56	5			1.82
2010		1.89	51				0.83	42			6.29	7			1.73

*  Includes refuse-derived fuel and wood.

See Item 1A for further discussion of fuel supply and costs.

Fuel Sources

Coal — The NSP System normally maintains approximately 41 days of coal inventory.  Coal supply inventories at Dec. 31, 2012 and 2011 were approximately 39 and 48 days usage, respectively.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana.  During 2012 and 2011, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.2 million tons and 9.5 million tons, respectively.  The estimated coal requirements for 2013 are approximately 8.6 million tons.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 97 percent of their coal requirements in 2013, and a declining percentage of the requirements in subsequent years.  The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of  requirements in two years, and 33 percent of requirements in three years.  Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 and 80 percent of their coal requirements in 2013 and 2014, respectively.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Nuclear — To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication.  The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

· Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 67 percent of the requirements for 2019 through 2025.

· Current contracts for conversion services cover 100 percent of the requirements through 2020 and approximately 67 percent of the requirements for 2021 through 2025.

· Current enrichment service contracts cover 99.7 percent of the requirements through 2022 and approximately 84 percent of the requirements for 2023 through 2025.

Fabrication services for Monticello and Prairie Island are 100 percent committed through 2025 and 2014, respectively.  A contract for fuel fabrication services for Prairie Island is currently being negotiated for 2015 and beyond.

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

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Natural gas — The NSP System uses both firm and interruptible natural gas supply 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.  However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market.  Generally, natural gas supply contracts have pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC approved transportation tariff rates.  These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2012 and 2011, the NSP System did not have any commitments related to gas supply contracts; however, commitments related to gas transportation and storage contracts were approximately $384 million and $462 million, respectively.  Commitments related to gas transportation and storage contracts expire in various years from 2013 to 2028.

The NSP System also has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs.  As of Dec. 31, 2012, the NSP System was in compliance with mandated RPSs, which require generation from renewable resources of 18 percent and 8.89 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.  Renewable energy comprised 22.0 percent and 19.7 percent of the NSP System’s total owned and purchased energy for 2012 and 2011, respectively.  Wind energy comprised 11.9 percent and 9.4 percent of the total owned and purchased energy on the NSP System for 2012 and 2011, respectively.  Hydroelectric energy comprised 7.0 percent and 7.5 percent of the total owned and purchased energy on the NSP System for 2012 and 2011, respectively.  Biomass and solar power comprised approximately 3.1 percent and 2.8 percent of renewable energy for 2012 and 2011, respectively.

The NSP System also offers customer-focused renewable energy initiatives.  Windsource®, one of the nation’s largest voluntary renewable energy programs, allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources.   Approximately 24,000 and 23,000 customers purchased 184,000 MWh and 177,000 MWh of electricity under the Windsource program in 2012 and 2011, respectively.  Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program.  Over 561 PV systems with approximately 6.7 MW of aggregate capacity and over 300 PV systems with approximately 3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2012 and 2011, respectively.

Wind—The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily in Southwestern Minnesota. The NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under 1 MW to more than 200 MW.  In 2012, the NSP System began purchasing wind from three new projects, which provided approximately 266 MW of capacity.  The largest of these projects, the Prairie Rose Wind Project began commercial operations in December 2012 and the NSP System will purchase the entire output from this 200 MW project.  In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.  The average cost per MWh of wind energy under these contracts was approximately $41 and $39 for 2012 and 2011, respectively.  The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state specific renewable resource requirements, and the year of contract execution.  Generally, contracts executed in 2012 benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to the anticipated expiration of the Federal PTCs in 2012.  In January 2013, the Federal PTC was extended through 2013.

The NSP System also owns and operates two wind farms.  The 101 MW Grand Meadow Wind Farm and the 201 MW Nobles Wind Farm began generating electricity in 2008 and 2010, respectively.  Collectively, the NSP System had over 1,870 MW and over 1,600 MW of wind energy on its system at the end of 2012 and 2011, respectively.

Hydroelectric—The NSP System acquires its hydroelectric energy from both owned generation and PPAs.  The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 274 MW of capacity.  For most of 2012, there were nine PPAs in place which provided approximately 37 MW of hydroelectric capacity.  Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

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Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Wisconsin, including enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of NSP-Wisconsin’s activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 10 to the accompanying consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) —The FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively.  For the Wisconsin portion of the NSP System, the impacts of the new requirements relating to future transmission development and ownership are uncertain.  The requirements for transmission planning and cost allocation were addressed by revisions to the MISO Tariff for NSP-Wisconsin as discussed below in MISO Transmission Pricing.

Xcel Energy Services Inc. and NSP-Wisconsin vs. ATC (La Crosse, Wis. to Madison, Wis. Transmission Line) — In February 2012, Xcel Energy Services Inc. and NSP-Wisconsin filed a complaint with the FERC concerning ownership of the proposed La Crosse, Wis. to Madison, Wis. 345 KV transmission line.  In July 2012, the FERC granted Xcel Energy Services Inc.’s and NSP-Wisconsin’s complaint, ruling that the responsibilities to construct the La Crosse, Wis. to Madison, Wis. transmission line belong equally to both parties.  In August 2012, American Transmission Company LLC (ATC) requested rehearing and requested that the FERC grant a stay of the ruling.  In September 2012, the FERC granted rehearing for purposes of further consideration but did not grant a stay.  Thus, the July ruling remains in effect pending the FERC’s further ruling on rehearing.  In order to proceed with development of the project, the two companies are working together on routing and regulatory state issues pending FERC action on ATC’s request for rehearing.  In addition, ITC Midwest LLC filed a similar complaint against ATC with the FERC concerning ownership of the Dubuque, Iowa to Cardinal (Madison, Wis.) line, a 136 mile, 345 KV transmission line that is also a MISO MVP project and that connects in Madison, Wis. to the La Crosse, Wis. to Madison, Wis. line.  In February 2013, the FERC granted the ITC Midwest complaint.

ATC vs. Xcel Energy Services Inc. and MISO (Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. Transmission Line) — In October 2012, ATC filed a complaint against MISO, Xcel Energy Services Inc., NSP-Minnesota and NSP-Wisconsin, alleging that, under the legal principles set forth in the July 2012 FERC ruling in the La Crosse to Madison transmission line complaint filed by Xcel Energy Services Inc. on behalf of its subsidiary NSP-Wisconsin against ATC, that the FERC should determine that MISO should have designated the Hampton to Rochester to La Crosse CapX2020 line and the La Crosse to Madison line as a single facility under the MISO Transmission Owners Agreementand Tariff.  Thus, ATC should have been designated as the owner of the La Crosse to Madison line portion of the purported single facility.  Xcel Energy filed an answer seeking dismissal of the ATC complaint in October 2012.  On Feb. 4, 2013, the FERC issued an order denying the ATC complaint.  The FERC found that MISO properly applied its planning process and that Hampton to La Crosse and the La Crosse to Madison lines are separate.  Therefore, MISO’s prior ownership decisions stand.

ARCs — In 2009, the FERC adopted rules requiring RTOs to allow ARCs to offer demand response aggregation services to end-use customers of large utilities unless the relevant state regulatory agency prohibited the operation of ARCs.  Under MISO’s proposed tariff revisions, ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Wisconsin.  In 2010, MISO requested its compliance tariff revisions be effective in June 2010, and the PSCW and MPSC all issued orders prohibiting, or temporarily prohibiting, the operation of ARCs in their states.

In December 2011, the FERC issued orders denying rehearing of the rules and approving most aspects of the MISO compliance filing.  The FERC retained the rules allowing state regulatory authorities to prohibit ARCs within their state.

Electric Transmission Rate Regulation — The FERC regulates the rates and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO.  The NSP System is a member 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.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments: some lower voltage projects are fully allocated to loads near the project vicinity, and other reliability projects are allocated 20 percent regionally and 80 percent to local loads.  If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region.  MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to provide multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving.  Certain parties have appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit.

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In its Order 1000 compliance filing in October 2012, MISO proposed that all future reliability projects be fully allocated to the zones in which the project is located (rather than allocating costs more broadly) while MVP projects would continue to be eligible for regional cost allocation.   FERC action is anticipated in 2013.  The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery.  Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities.  The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation could be significant in future periods.

RSG Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy.  In August 2010, the FERC issued two orders relating to RSG charge exemptions and the allocation of the RSG costs among MISO participants.  In recent RSG filings, MISO has proposed, and the FERC has accepted, allocating a greater portion of the RSG costs related to resources committed for voltage and local reliability requirements to the market participants with the loads that benefit from such commitments.  NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms approved by the regulators in each jurisdiction.  Certain of the FERC’s orders remain pending on rehearing, and appeals of the FERC orders to the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) have been held in abeyance, pending the FERC’s disposition of rehearing requests.

Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2012			2011			2010
Electric sales (Millions of KWh)
Residential		1,921			1,982			1,962
Large commercial and industrial		1,739			1,678			1,600
Small commercial and industrial		2,763			2,718			2,720
Public authorities and other		35			33			35
Total retail		6,458			6,411			6,317
Sales for resale		412			546			546
Total energy sold		6,870			6,957			6,863
Number of customers at end of period
Residential		211,727			211,369			210,781
Large commercial and industrial		108			103			100
Small commercial and industrial		38,359			37,933			37,773
Public authorities and other		1,153			1,156			1,151
Total retail		251,347			250,561			249,805
Wholesale		9			10			10
Total customers		251,356			250,571			249,815
Electric revenues (Thousands of Dollars)
Residential	$	223,191		$	226,159		$	213,060
Large commercial and industrial		120,694			116,715			101,293
Small commercial and industrial		247,003			240,168			234,432
Public authorities and other		5,762			5,657			5,241
Total retail		596,650			588,699			554,026
Wholesale		31,583			37,884			33,471
Interchange revenues from NSP-Minnesota		125,344			124,334			116,312
Other electric revenues		3,988			4,219			4,370
Total electric revenues	$	757,565		$	755,136		$	708,179
KWh sales per retail customer		25,694			25,587			25,288
Revenue per retail customer	$	2,374		$	2,350		$	2,218
Residential revenue per KWh		11.62	¢		11.41	¢		10.86	¢
Large commercial and industrial revenue per KWh		6.94			6.96			6.33
Small commercial and industrial revenue per KWh		8.94			8.84			8.62
Wholesale revenue per KWh		7.67			6.94			6.13

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Energy Source Statistics

	Year Ended Dec. 31
	2012					2011					2010
NSP System	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		16,023		35	%		20,131		44	%		19,579		42	%
Nuclear		13,231		29			13,332		29			14,628		31
Natural Gas		6,200		13			3,016		7			3,887		8
Wind (a)		5,443		12			4,312		9			3,760		8
Hydroelectric		3,193		7			3,444		8			3,487		7
Other (b)		1,617		4			1,453		3			1,494		4
Total		45,707		100	%		45,688		100	%		46,835		100	%
Owned generation		31,365		69	%		31,668		69	%		33,758		72	%
Purchased generation		14,342		31			14,020		31			13,077		28
Total		45,707		100	%		45,688		100	%		46,835		100	%

(a) This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  The NSP System uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b) Includes energy from other sources, including solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of NSP-Wisconsin are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small commercial and industrial (C&I) customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 2000 to 2012, average annual sales to the typical NSP-Wisconsin residential customer declined from 85 MMBtu per year to 69 MMBtu per year, and to the typical small C&I customer increased from 491 MMBtu per year to 498 MMBtu per year, on a weather-normalized basis.  The increase in C&I is due to new load growth.  Although wholesale price increases do not directly affect earnings because of natural gas cost-recovery mechanisms, high prices can encourage further efficiency efforts by customers.

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires, among other things, additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. Where records are inadequate to confirm the maximum allowable operating pressure, the DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure.  This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations, addressing a variety of subjects, including: requiring use of automatic or remote-controlled shut-off valves in certain circumstances; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2 million for a related series of violations. While NSP-Wisconsin cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, NSP-Wisconsin is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

Public Utility Regulation

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

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Natural Gas Cost-Recovery Mechanisms — NSP-Wisconsin has a retail purchased gas adjustment cost-recovery mechanism for Wisconsin operations to recover the actual cost of natural gas and transportation and storage services.  The PSCW has the authority to disallow certain costs if it finds NSP-Wisconsin 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.

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 143,134 MMBtu, which occurred on Jan. 19, 2012, and 134,636 MMBtu, which occurred on Jan. 20, 2011.

NSP-Wisconsin purchases natural gas from independent suppliers, generally based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of approximately 133,153 MMBtu per day.  In addition, NSP-Wisconsin contracts 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 2012-2013 supply plan was approved by the PSCW in October 2012.

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.

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:

2012	$	4.36
2011		5.18
2010		5.46

The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment mechanisms.  NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2013 through 2029.

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, 2012, NSP-Wisconsin was committed to approximately $86 million in such obligations under these contracts.

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

See Item 1A for further discussion of natural gas supply and costs.

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Natural Gas Operating Statistics

	Year Ended Dec. 31
	2012		2011		2010
Natural gas deliveries (Thousands of MMBtu)
Residential		5,737		6,571		6,278
Commercial and industrial		8,197		8,476		8,063
Total retail		13,934		15,047		14,341
Transportation and other		4,177		3,983		3,827
Total deliveries		18,111		19,030		18,168
Number of customers at end of period
Residential		95,715		94,430		93,402
Commercial and industrial		12,506		12,392		12,288
Total retail		108,221		106,822		105,690
Transportation and other		22		22		22
Total customers		108,243		106,844		105,712
Natural gas revenues (Thousands of Dollars)
Residential	$	51,302	$	60,772	$	59,675
Commercial and industrial		47,771		57,077		56,218
Total retail		99,073		117,849		115,893
Transportation and other		4,027		1,598		2,183
Total natural gas revenues	$	103,100	$	119,447	$	118,076
MMBtu sales per retail customer		128.76		140.86		135.69
Revenue per retail customer	$	915	$	1,103	$	1,097
Residential revenue per MMBtu		8.94		9.25		9.51
Commercial and industrial revenue per MMBtu		5.83		6.73		6.97
Transportation and other revenue per MMBtu		0.96		0.40		0.57

GENERAL

Seasonality

The demand for electric power and natural gas is affected by seasonal differences in the weather.  In general, peak sales of electricity occur in the summer and winter months, and peak sales of natural gas occur in the winter months.  As a result, the overall operating results may fluctuate substantially on a seasonal basis.  Additionally, NSP-Wisconsin’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.  See Item 7 — Management’s Discussion of Financial Condition and Results of Operations.

Competition

NSP-Wisconsin’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity.  In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  The FERC has continued to promote competitive wholesale markets through open access transmission and other means.  As a result, NSP-Wisconsin and its wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.  While facing these challenges, NSP-Wisconsin’s believes its rates are competitive with currently available alternatives.

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In December 2010, NSP-Wisconsin’s two largest wholesale customers, the cities of Rice Lake, Wis. and Medford, Wis., each issued a notice canceling their wholesale power contracts with NSP-Wisconsin.  Effective Jan. 1, 2012, Medford, Wis. began purchasing power from an alternate supplier.  In 2011, the other eight NSP-Wisconsin wholesale customers issued notices canceling their wholesale power contracts effective Dec. 31, 2012 and began to purchase from an alternate supplier, along with Rice Lake, Wis. effective Jan. 1, 2013.  In 2012, these eight remaining wholesale customers represented approximately 4 percent of NSP-Wisconsin’s total electric operating revenues.

ENVIRONMENTAL MATTERS

NSP-Wisconsin’s facilities are regulated by federal and state environmental agencies.  These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances.  Various company activities require registrations, permits, licenses, inspections and approvals from these agencies.  NSP-Wisconsin has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.  NSP-Wisconsin’s 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.  See Notes 10 and 11to the consolidated financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.  While environmental regulations related to climate change and clean energy continue to evolve, NSP-Wisconsin has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals.  Although the impact of these policies on NSP-Wisconsin will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2012, NSP-Wisconsin had 578 full-time employees and 4 part-time employees, of which 405 were covered under collective-bargaining agreements.  See Note 7 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

Like other companies in our industry, Xcel Energy, which includes NSP-Wisconsin, is subject to a variety of risks, many of which are beyond our control.  Important risks that may adversely affect the business, financial condition, and results of operations are further described below.  These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

There may be further risks and uncertainties that are not presently known or are not currently believed to be material that may adversely affect our performance or financial condition in the future.

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes NSP-Wisconsin, is to understand, manage and, when possible, mitigate material risk.  Management is responsible for identifying and managing risks, while Xcel Energy Inc.’s Board of Directors oversees and holds management accountable.  As described more fully below, NSP-Wisconsin is faced with a number of different types of risk.  Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy Inc.’s and NSP-Wisconsin’s senior management.  Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

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

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

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

Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental registrations including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2012, these sites included:

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

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

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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 effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial position or cash flows.

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

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

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

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

Increased energy use due to weather changes may require us to invest in additional 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 stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

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

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

Financial Risks

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

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

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.  We currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated and based on an analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital in a continued low interest rate environment there could be pressure on ROE.  There can also 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.

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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 or climate change regulation, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

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

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.  In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.  Any downgrade could lead to higher borrowing costs.  Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

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

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

We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily.  The Dodd-Frank Wall Street Reform Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity: however, we expect to take advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant.  The Commodity Futures Trading Commission (CFTC) has granted an increase in the de minimis level for swap transactions with defined utility special entities, generally entities owning or operating electric or natural gas facilities, from $25 million to $800 million.  Our current level of financial swap activity with special entities is significantly below this new threshold; therefore, we will not be classified as a swap dealer in our special entity activity.   Swap transactions with non special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act.  While we believe the impact on our liquidity will not be material, we expect to be required to report our swap transactions as part of the Dodd-Frank Act.

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

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008 with modifications to these funding requirements in 2012 that allowed additional flexibility in the timing of contributions.  Therefore, our funding requirements and related contributions may change in the future.  Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

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

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

Operational Risks

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products, and are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility.  Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such disruption, if significant, could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.  The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.

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

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

Although we do not own any nuclear generating facilities, because our production and transmission system is operated on an integrated basis with NSP-Minnesota’s (an affiliate of NSP-Wisconsin) 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 use of radioactive material in the production of energy, the management, handling, storage and disposal of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

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

· Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses at NSP-Minnesota’s nuclear plants. In addition, the Institute for Nuclear Power Operations reviews NSP-Minnesota’s nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

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

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

On a periodic basis 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, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology on energy efficiency patterns on sales and production, customer behavioral response and continuation of the existing utility business model.  Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide.  This could lead to under recovery of costs or insufficient resources to meet customer demand.

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In some of our state jurisdictions, large industrial customers may leave our system and invest in their own on-site distributed generation or seek law changes to give them the authority to purchase directly from other suppliers or organized markets.  The recent low natural gas price environment has caused some customers to consider their options in this area, particularly customers with industrial processes using steam.  These circumstances provide for greater long-term planning uncertainty related to future load growth.  Similarly, distributed solar generation may become an economic competitive threat to our load growth in the future, however we believe the economics, absent significant subsidies, do not support such a trend in the near term unless a state mandates the purchase of such generation.  Some state legislatures have considered such legislation.

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

Our natural gas transmission and distribution activities include a variety of inherent 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 effect on our financial position and results of operations.  For our natural gas transmission or distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks is greater.

Additionally, the cost of potential regulations related to pipeline safety could be significant.

As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. 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 Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets.  This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2012, Xcel Energy Inc. and its utility subsidiaries had approximately $10.1 billion of long-term debt and $0.9 billion of short-term debt and current maturities.  Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy Inc.’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 Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2012, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $69.5 million and $17.9 million of exposure.  Xcel Energy also had additional guarantees of $29.6 million at Dec. 31, 2012 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.  If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. 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.

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

All of the members of our board of directors, as well as many of our executive officers, are officers of Xcel Energy Inc.  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 Inc.  In 2012, 2011 and 2010 we paid $57.3 million, $32.9 million and $73.9 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change.  Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA.  In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants, although it is not known when the EPA will initiate this rulemaking.

We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 11 to the consolidated financial statements.  An adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

There are many uncertainties regarding when and in what form climate change legislation or regulations will be enacted.  The impact of legislation and regulations, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are recognized as compliance options, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities.  These include, but are not limited to, rules associated with emissions of SO2 and NOx, mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

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

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The FERC has provided notice of violations of its market manipulation rules to several market participants during the year.  The potential penalties in one pending case exceed $400 million.  As with all regulatory requirements, we attempt to mitigate this risk through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions.  However, there is no guarantee our compliance program will be sufficient to ensure against violations.

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged economic recession and uncertainty of recovery may result in a sustained lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets.  A sustained lower level of economic activity may also result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.

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

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

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material 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 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.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance may decrease.  In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.  For example, wildfire events, particularly in the geographic areas we serve may cause insurance for wildfire losses to become difficult or expensive to obtain.

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

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

A cyber incident or cyber security breach could have a material effect on our business.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  In addition, in the ordinary course of business, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems, infrastructure and assets could be directly or indirectly affected by unintentional or deliberate cyber security incidents, including those caused by human error.  Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to liability.  As generation and transmission systems as well as natural gas pipelines are part of an interconnected system, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources or of our third party service providers’ operations,  could also negatively impact our business.  In addition, we also anticipate that such an event would receive regulatory scrutiny at both the Federal and State level.  We are unable to quantify the potential impact of such cyber security threats or subsequent related actions.  These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

Although we maintain security measures designed to protect our information technology systems, network infrastructure and other assets, these assets as well as the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information.   If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business.

Rising energy prices could negatively impact our business.

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

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

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

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

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

Electric Utility Generating Stations:

			Summer 2012
			Net Dependable
Station, Location and Unit	Fuel	Installed	Capability (MW)
Steam:
Bay Front-Ashland, Wis., 3 Units	Coal/Wood/Natural Gas	1948-1956	56
French Island-La Crosse, Wis., 2 Units	Wood/Refuse-derived fuel	1940-1948	16	(a)
Combustion Turbine:
Flambeau Station-Park Falls, Wis., 1 Unit	Natural Gas	1969	12
French Island-La Crosse, Wis., 2 Units	Natural Gas	1974	122
Wheaton-Eau Claire, Wis., 6 Units	Natural Gas	1973	290
Hydro:
Various locations, 63 Units	Hydro	Various	135
		Total	631

(a) Refuse-derived fuel is made from municipal solid waste.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2012:

Conductor Miles
345 KV	1,152
161 KV	1,568
115 KV	1,737
Less than 115 KV	32,090

NSP-Wisconsin had 204 electric utility transmission and distribution substations at Dec. 31, 2012.

Natural gas utility mains at Dec. 31, 2012:

Miles
Distribution	2,243

Item 3 — Legal Proceedings

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

Additional Information

See Note 11 to the consolidated financial statements for further discussion of legal claims and environmental proceedings.  See Item 1 and Note 10 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 4 — Mine Safety Disclosures

None.

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 Inc. and there is no market for its common equity securities.

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NSP-Wisconsin has dividend restrictions imposed by FERC rules and state regulatory commissions:

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

· The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of approximately $31.8 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent.  NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio was 52.6 percent at Dec. 31, 2012.

See Note 4 to the consolidated financial statements for further discussion of NSP-Wisconsin’s dividend policy.

The dividends declared during 2012 and 2011 were as follows:

(Thousands of Dollars)	2012		2011
First quarter	$	8,119	$	8,287
Second quarter		8,080		8,112
Third quarter		33,005		8,101
Fourth quarter		7,667		8,107

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 of the results of operations set forth in general instructions I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Wisconsin and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Wisconsin has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Wisconsin and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP- Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto.

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Results of Operations

NSP-Wisconsin’s net income was $50.0 million for 2012, compared with $51.0 million for 2011.  Net income was positively impacted by rate increases, effective January 2012, offset by higher O&M expenses.

Electric Revenues and Margin

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

(Millions of Dollars)	2012			2011
Electric revenues	$	758		$	755
Electric fuel and purchased power		(425	)		(421	)
Electric margin	$	333		$	334

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

Electric Revenues

(Millions of Dollars)	2012 vs. 2011
Retail rate increases (Wisconsin and Michigan)	$	11
Demand revenue		5
Fuel and purchased power cost recovery		4
Retail sales increase, excluding weather impact		2
Conservation revenue (offset by expenses)		2
Sales mix		(11	)
Firm wholesale		(6	)
Estimated impact of weather		(3	)
Other, net		(1	)
Total increase in electric revenues	$	3

Electric Margin

(Millions of Dollars)	2012 vs. 2011
Sales mix	$	(11	)
Fuel and purchased power cost recovery		(7	)
Firm wholesale		(3	)
Estimated impact of weather		(3	)
Retail rate increases (Wisconsin and Michigan)		11
Demand revenue		5
Interchange agreement billings with NSP-Minnesota		4
Retail sales increase, excluding weather impact		2
Conservation revenue (offset by expenses)		2
Other, net		(1	)
Total decrease in electric margin	$	(1	)

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Natural Gas Revenues and Margin

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

(Millions of Dollars)	2012			2011
Natural gas revenues	$	103		$	119
Cost of natural gas sold and transported		(61	)		(78	)
Natural gas margin	$	42		$	41

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

Natural Gas Revenues

(Millions of Dollars)	2012 vs. 2011
Purchased natural gas adjustment clause recovery	$	(17	)
Estimated impact of weather		(3	)
Retail rate increase (Wisconsin)		3
Other, net		1
Total decrease in natural gas revenues	$	(16	)

Natural Gas Margin

(Millions of Dollars)	2012 vs. 2011
Retail rate increase (Wisconsin)	$	3
Estimated impact of weather		(3	)
Other, net		1
Total increase in natural gas margin	$	1

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $3.2 million, or 1.9 percent, for 2012 compared with 2011.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2012 vs. 2011
Higher interchange agreement billing costs with NSP-Minnesota	$	4
Higher employee benefit expense		3
Lower plant generation costs		(2	)
Other, net		(2	)
Total increase in O&M expenses	$	3

· Higher interchange costs are due to increased fixed charges.

· Higher employee benefits are due to increased pension expenses.

· Lower plant generation costs are primarily attributable to fewer plant overhauls in 2012.

Income Taxes — Income tax expense decreased by $4.1 million for 2012, compared with 2011.  The decrease in income tax expense was primarily due to tax expense from prior year adjustments in 2011 and lower pretax earnings in 2012.  The ETR was 37.2 percent for 2012, compared with 39.7 percent for 2011.  The higher ETR for 2011 was primarily due to increased plant-related income tax expense and prior year adjustments in 2011.

The ETRs for  2012 and 2011 differ from the statutory federal income tax rate, primarily due to state income tax expense.  See Note 6 to the consolidated financial statements for further discussion.

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Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, NSP-Wisconsin is exposed to a variety of market risks.  Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity.  All financial and commodity-related instruments, including derivatives, are subject to market risk.  See Note 9 to the consolidated financial statements for further discussion of market risks associated with derivatives.

NSP-Wisconsin is exposed to the impact of adverse changes in price for energy and energy related products, which is partially mitigated by the use of commodity derivatives.  In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral.  While NSP-Wisconsin expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose NSP-Wisconsin to some credit and nonperformance risk.

Though no material non-performance risk currently exists with the counterparties to NSP-Wisconsin’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties.  Distress in the financial markets may also impact the fair value of the securities in the master pension trust, as well as NSP-Wisconsin’s ability to earn a return on short-term investments of excess cash.

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

At Dec. 31, 2012 and 2011, a 100-basis-point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact pretax interest expense annually by approximately $0.4 million and $0.7 million, respectively.  See Note 9 to the consolidated financial statements for a discussion of NSP-Wisconsin’s interest rate derivatives.

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

At Dec. 31, 2012 and 2011, a 10 percent increase or decrease in commodity prices would have an immaterial impact on credit exposure.

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

Item 8 — Financial Statements and Supplementary Data

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

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

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Management Report on Internal Controls Over Financial Reporting

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

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

NSP-Wisconsin management assessed the effectiveness of NSP-Wisconsin’s internal control over financial reporting as of Dec. 31, 2012.  In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.  Based on our assessment, we believe that, as of Dec. 31, 2012, NSP-Wisconsin’s internal control over financial reporting is effective based on those criteria.

/s/ MARK E. STOERING	/s/ TERESA S. MADDEN
Mark E. Stoering	Teresa S. Madden
President, Chief Executive Officer and Director	Senior Vice President, Chief Financial Officer and Director
Feb. 25, 2013	Feb. 25, 2013

29

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Northern States Power Company, a Wisconsin corporation

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company, a Wisconsin corporation, and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2012.  Our audits also included the financial statement schedule listed in the Index at Item 15.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company, a Wisconsin corporation, and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 25, 2013

30

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2012			2011			2010
Operating revenues
Electric	$	757,565		$	755,136		$	708,179
Natural gas		103,100			119,447			118,076
Other		1,177			1,207			1,036
Total operating revenues		861,842			875,790			827,291
Operating expenses
Electric fuel and purchased power, non-affiliates		19,440			20,957			22,222
Purchased power, affiliates		405,016			399,649			377,518
Cost of natural gas sold and transported		61,370			78,208			78,176
Operating and maintenance expenses		167,503			164,323			160,824
Conservation program expenses		14,442			12,883			12,965
Depreciation and amortization		69,234			68,574			63,669
Taxes (other than income taxes)		24,971			23,688			23,096
Total operating expenses		761,976			768,282			738,470
Operating income		99,866			107,508			88,821
Other income, net		476			98			1,265
Allowance for funds used during construction — equity		2,104			1,007			2,253
Interest charges and financing costs
Interest charges — includes other financing costs of
$1,574, $1,713 and $1,420, respectively		24,799			24,168			24,517
Allowance for funds used during construction — debt		(1,862	)		(175	)		(1,039	)
Total interest charges and financing costs		22,937			23,993			23,478
Income before income taxes		79,509			84,620			68,861
Income taxes		29,558			33,614			26,112
Net income	$	49,951		$	51,006		$	42,749

See Notes to Consolidated Financial Statements

31

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2012		2011		2010
Net income	$	49,951	$	51,006	$	42,749
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of
$51, $51 and $51, respectively		77		76		76
Other comprehensive income		77		76		76
Comprehensive income	$	50,028	$	51,082	$	42,825

See Notes to Consolidated Financial Statements

32

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2012			2011			2010
Operating activities
Net income	$	49,951		$	51,006		$	42,749
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		70,372			69,900			64,996
Deferred income taxes		27,107			35,610			20,714
Amortization of investment tax credits		(626	)		(611	)		(622	)
Allowance for equity funds used during construction		(2,104	)		(1,007	)		(2,253	)
Provision for bad debts		3,329			3,842			3,294
Net derivative losses		127			127			127
Changes in operating assets and liabilities:
Accounts receivable		(15,953	)		(4,013	)		15,556
Accrued unbilled revenues		(470	)		2,911			(6,672	)
Inventories		6,018			913			1,827
Other current assets		(3,172	)		(1,180	)		6,872
Accounts payable		5,828			(16,614	)		(5,668	)
Net regulatory assets and liabilities		3,623			10,008			(3,207	)
Other current liabilities		3,681			(2,260	)		1,131
Pension and other employee benefit obligations		(10,857	)		(7,214	)		(3,113	)
Change in other noncurrent assets		14			564			867
Change in other noncurrent liabilities		(595	)		(2,682	)		5,260
Net cash provided by operating activities		136,273			139,300			141,858
Investing activities
Utility capital/construction expenditures		(152,759	)		(140,982	)		(128,933	)
Allowance for equity funds used during construction		2,104			1,007			2,253
Other, net		916			(112	)		2,291
Net cash used in investing activities		(149,739	)		(140,087	)		(124,389	)
Financing activities
(Repayments of) proceeds from short-term borrowings, net		(27,000	)		66,000			-
Proceeds from notes payable to affiliates		50			111,300			302,300
Repayments of notes payable to affiliates		-			(148,350	)		(280,850	)
Proceeds from issuance of long-term debt		97,916			-			-
Repayments of long-term debt		(97	)		(96	)		(95	)
Capital contributions from parent		2,796			-			40,566
Dividends paid to parent		(57,311	)		(32,941	)		(73,868	)
Net cash provided by (used in) financing activities		16,354			(4,087	)		(11,947	)
Net change in cash and cash equivalents		2,888			(4,874	)		5,522
Cash and cash equivalents at beginning of period		1,571			6,445			923
Cash and cash equivalents at end of period	$	4,459		$	1,571		$	6,445
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(21,035	)	$	(22,616	)	$	(22,154	)
Cash (paid) received for income taxes, net		(5,841	)		1,116			4,371
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	10,618		$	9,427		$	3,630

See Notes to Consolidated Financial Statements

33

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands, except share and per share data)

	Dec. 31
	2012			2011
Assets
Current assets
Cash and cash equivalents	$	4,459		$	1,571
Accounts receivable, net		50,706			51,838
Accrued unbilled revenues		49,138			48,668
Inventories		19,685			25,703
Regulatory assets		12,048			14,133
Prepaid taxes		24,688			21,841
Prepayments and other		4,394			2,991
Total current assets		165,118			166,745
Property, plant and equipment, net		1,298,236			1,207,698
Other assets
Regulatory assets		240,459			229,910
Other investments		3,232			4,148
Other		4,040			2,970
Total other assets		247,731			237,028
Total assets	$	1,711,085		$	1,611,471
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,246		$	1,286
Short-term debt		39,000			66,000
Notes payable to affiliates		550			500
Accounts payable		30,723			30,897
Accounts payable to affiliates		31,556			23,285
Dividends payable to parent		7,667			8,107
Regulatory liabilities		6,086			16,609
Environmental liabilities		23,427			30,699
Accrued interest		7,304			6,521
Other		11,794			13,907
Total current liabilities		159,353			197,811
Deferred credits and other liabilities
Deferred income taxes		261,800			234,222
Deferred investment tax credits		8,911			8,499
Regulatory liabilities		123,746			119,187
Environmental liabilities		84,655			79,399
Customer advances		15,631			15,765
Pension and employee benefit obligations		63,643			60,328
Other		8,923			7,024
Total deferred credits and other liabilities		567,309			524,424
Commitments and contingencies
Capitalization
Long-term debt		467,317			368,083
Common stock — 1,000,000 shares authorized of $100 par value; 933,000
shares outstanding at Dec. 31, 2012 and 2011, respectively		93,300			93,300
Additional paid in capital		189,867			187,071
Retained earnings		234,376			241,296
Accumulated other comprehensive loss		(437	)		(514	)
Total common stockholder’s equity		517,106			521,153
Total liabilities and equity	$	1,711,085		$	1,611,471

See Notes to Consolidated Financial Statements

34

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in thousands, except share data)

	Common Stock									Accumulated			Total
					Additional					Other			Common
					Paid In		Retained			Comprehensive			Stockholder’s
	Shares		Par Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2009		933,000	$	93,300	$	146,505	$	253,935		$	(666	)	$	493,074
Comprehensive income:
Net income								42,749						42,749
Other comprehensive income											76			76
Comprehensive income for 2010														42,825
Common dividends declared to parent								(73,787	)					(73,787	)
Contribution of capital by parent						40,566								40,566
Balance at Dec. 31, 2010		933,000	$	93,300	$	187,071	$	222,897		$	(590	)	$	502,678
Comprehensive income:
Net income								51,006						51,006
Other comprehensive income											76			76
Comprehensive income for 2011														51,082
Common dividends declared to parent								(32,607	)					(32,607	)
Contribution of capital by parent						-								-
Balance at Dec. 31, 2011		933,000	$	93,300	$	187,071	$	241,296		$	(514	)	$	521,153
Comprehensive income:
Net income								49,951						49,951
Other comprehensive income											77			77
Comprehensive income for 2012														50,028
Common dividends declared to parent								(56,871	)					(56,871	)
Contribution of capital by parent						2,796								2,796
Balance at Dec. 31, 2012		933,000	$	93,300	$	189,867	$	234,376		$	(437	)	$	517,106

See Notes to Consolidated Financial Statements

35

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousands, except share and per share data)

	Dec. 31
	2012			2011
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
Sept. 1, 2038, 6.375%		200,000			200,000
Oct. 1, 2042, 3.7%		100,000			-
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%		591			625
Other		1,829			1,892
Unamortized discount		(2,457	)		(1,748	)
Total		468,563			369,369
Less current maturities		1,246			1,286
Total long-term debt	$	467,317		$	368,083
Common Stockholder’s Equity
Common stock  — 1,000,000 authorized shares of $100 par value;
933,000 shares outstanding at Dec. 31, 2012 and 2011, respectively	$	93,300		$	93,300
Additional paid in capital		189,867			187,071
Retained earnings		234,376			241,296
Accumulated other comprehensive loss		(437	)		(514	)
Total common stockholder’s equity	$	517,106		$	521,153

(a) Resource recovery financing

See Notes to Consolidated Financial Statements

36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— NSP-Wisconsin is principally engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Wisconsin’s underlying accounting records also 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’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary.  In the consolidation process, all intercompany transactions and balances are eliminated.

NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary.  NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary.  See Note 11 for further discussion of variable interest entities.

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, regulatory assets and liabilities, 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.

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

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

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

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

If restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows.  See Note 12 for further discussion of regulatory assets and liabilities.

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

NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas costs.  These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically, for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

37

Requests can be made for recovery of purchased electric energy or fuel for generation prospectively through the rate review process, which normally occurs every two years, or at an interim fuel cost hearing process.  Effective 2011, NSP-Wisconsin began submitting a forward looking fuel cost plan that allows for deferral of fuel cost under-collection or over-collection in excess of a two percent annual tolerance band, for future rate recovery or refund.  Fuel costs are subject to PSCW hearings and approval, and other requirements.  NSP-Wisconsin’s wholesale electric rate schedules include an FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

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

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 AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit 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.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.  Property, plant and equipment that is to be early decommissioned is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable.  Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period.  For investments in property, plant and equipment that are not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss on abandonment is recognized, if necessary.

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5, 3.6, and 3.5 percent for the years ended Dec. 31, 2012, 2011, and 2010, respectively.

Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease.  See Note 11 for further discussion of leases.

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

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.

Asset Retirement Obligations — NSP-Wisconsin records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with the applicable accounting guidance.  This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the amounts through the establishment of a regulatory asset and recovery in rates.

NSP-Wisconsin also recovers currently in rates certain future plant removal costs in addition to AROs and related capitalized costs, and a regulatory liability is recognized for such future expenditures.  See Note 11 for further discussion of AROs.

38

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

Deferred tax assets are reduced by a valuation allowance if 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 evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense.  Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

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

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

Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  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 as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations.  Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.

39

Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.  See Note 9 for further discussion.

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.

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

Inventory— All inventory is recorded at average cost.

Renewable Energy Credits — RECs aremarketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources.  RECs are awarded upon delivery of the associated energy and can be bought and sold.  RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced.  NSP-Wisconsin acquires RECs from the generation or purchase of renewable power.  When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees.  NSP-Wisconsin follows the inventory accounting model for all emission allowances.  The sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

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

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

See Note 11 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 7 for further discussion of benefit plans and other postretirement benefits.

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

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The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2012 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2.  Accounting Pronouncements

Recently Adopted

Fair Value Measurement — In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Wisconsin implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements.  For required fair value measurement disclosures, see Notes 7 and 9.

Presentation of Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Wisconsin implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01) to clarify the specific instruments and activities that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Wisconsin does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

Comprehensive Income Disclosures— In February 2013, the FASB issued Comprehensive Income (Topic 220) -– Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures of the amounts reclassified out of accumulated other comprehensive income.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements are effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  NSP-Wisconsin does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2012			Dec. 31, 2011
Accounts receivable, net (a)
Accounts receivable	$	55,039		$	56,604
Less allowance for bad debts		(4,333	)		(4,766	)
	$	50,706		$	51,838

(a) Accounts receivable, net includes $586 due from affiliates as of Dec. 31, 2012.

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(Thousands of Dollars)	Dec. 31, 2012		Dec. 31, 2011
Inventories
Materials and supplies	$	6,172	$	5,838
Fuel		6,664		9,335
Natural gas		6,849		10,530
	$	19,685	$	25,703

(Thousands of Dollars)	Dec. 31, 2012			Dec. 31, 2011
Property, plant and equipment, net
Electric plant	$	1,795,239		$	1,684,537
Natural gas plant		224,625			213,665
Common and other property		111,319			113,597
Construction work in progress		62,629			54,627
Total property, plant and equipment		2,193,812			2,066,426
Less accumulated depreciation		(895,576	)		(858,728	)
	$	1,298,236		$	1,207,698

4.  Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2012
Borrowing limit	$	150
Amount outstandingat period end		39
Average amount outstanding		21
Maximum amount outstanding		101
Weighted average interest rate, computed on a daily basis		0.39	%
Weighted average interest rate at end of period		0.40

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	150		$	150
Amount outstandingat period end		39			66
Average amount outstanding		61			24
Maximum amount outstanding		116			70
Weighted average interest rate, computed on a daily basis		0.39	%		0.37	%
Weighted average interest rate at end of period		0.40			0.46

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, 2012 and 2011, there were no letters of credit outstanding.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Dec. 31, 2012, NSP-Wisconsin had the following committed credit facility available (in millions):

Credit Facility		Drawn (a)		Available
$	150.0	$	39.0	$	111.0

(a) Includes outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Wisconsin had no direct advances on the credit facility outstanding at Dec. 31, 2012 and 2011.

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Amended Credit Agreement — In July 2012, NSP-Wisconsin entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period, subject to majority bank group approval.

Other features of NSP-Wisconsin’s credit facility include:

· The credit facility has a financial covenant requiring that NSP-Wisconsin’s debt-to-total capitalization ratio be less than or equal to 65 percent.  NSP-Wisconsin was in compliance as its debt-to-total capitalization ratio was 50 percent at Dec. 31, 2012.  If NSP-Wisconsin does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

· The credit facility has a cross-default provision that provides NSP-Wisconsin will be in default on its borrowings under the facility if NSP-Wisconsin or any of its subsidiaries whose total assets exceed 15 percent of NSP-Wisconsin’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

Intercompany Borrowing Arrangement — Prior to entering into its credit facility, NSP-Wisconsin had an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate.  The borrowing arrangement terminated in the first quarter 2011, during which time there were no borrowings.  The following table presents the intercompany borrowing arrangement with NSP-Minnesota at Dec. 31, 2010:

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	100
Amount outstandingat period end		37
Average amount outstanding		11
Maximum amount outstanding		59
Weighted average interest rate, computed on a daily basis		0.33	%
Weighted average interest rate at end of period		0.38

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

(Amounts in Millions, Except Interest Rates)	Dec. 31, 2012			Dec. 31, 2011
Notes payable to affiliates	$	0.6		$	0.5
Weighted average interest rate		0.33	%		0.46	%

Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal property of NSP-Wisconsin is subject to the liens of its first mortgage indentures.  Additionally, debt premiums, discounts and expenses are amortized over the life of the related debt.  The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

In October 2012, NSP-Wisconsin issued $100 million of 3.70 percent first mortgage bonds due Oct. 1, 2042.

During the next five years, NSP-Wisconsin has long-term debt maturities of $1.2 million due in 2013.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $3.6 million and $2.6 million, net of amortization, at Dec. 31, 2012 and 2011, respectively.  NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

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Dividend Restrictions —NSP-Wisconsin’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of approximately $31.8 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent.  NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio was 52.6 percent at Dec. 31, 2012.

5.  Joint Ownership of Transmission Facilities

Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2012:

						Construction
	Plant in			Accumulated		Work in
(Thousands of Dollars)	Service			Depreciation		Progress		Ownership %
NSP-Wisconsin
Electric Transmission:
CapX2020 Transmission		$	9,630	$	4,689	$	1,235		76.6	%
Total NSP-Wisconsin		$	9,630	$	4,689	$	1,235

6.  Income Taxes

Medicare Part D — In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.

Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in September 2013.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011.  As of Dec. 31, 2012, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits — NSP-Wisconsinis a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2012,  NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008.  As of Dec. 31, 2012, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2012		Dec. 31, 2011
Unrecognized tax benefit - Permanent tax positions	$	0.1	$	-
Unrecognized tax benefit - Temporary tax positions		1.2		1.5
Total unrecognized tax benefit	$	1.3	$	1.5

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

(Millions of Dollars)	2012			2011			2010
Balance at Jan. 1	$	1.5		$	1.9		$	1.2
Additions based on tax positions related to the current year		0.5			0.6			0.7
Reductions based on tax positions related to the current year		(0.2	)		(0.1	)		-
Additions for tax positions of prior years		0.3			0.7			0.1
Reductions for tax positions of prior years		(0.8	)		(0.3	)		(0.1	)
Settlements with taxing authorities		-			(1.2	)		-
Lapse of applicable statutes of limitations		-			(0.1	)		-
Balance at Dec. 31	$	1.3		$	1.5		$	1.9

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

(Millions of Dollars)	Dec. 31, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(0.9	)	$	(1.1	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.   At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL carryforwards.  The payables for interest related to unrecognized tax benefits at Dec. 31, 2012, 2011, and 2010 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2012, 2011 or 2010.

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

(Millions of Dollars)	2012		2011
Federal NOL carryforward	$	44.3	$	59.3
Federal tax credit carryforwards		8.0		8.0
State NOL carryforward		3.4		3.5

The federal carryforward periods expire between 2021 and 2032.  The state carryforward periods expire in 2031.

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

	2012			2011			2010
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		3.4			4.4			3.5
Change in unrecognized tax benefits		0.1			(0.2	)		-
Tax credits recognized		(0.9	)		(0.9	)		(1.1	)
Regulatory differences — utility plant items		(0.3	)		0.5			(0.7	)
Medicare Part D		-			-			1.0
Other, net		(0.1	)		0.9			0.2
Effective income tax rate		37.2	%		39.7	%		37.9	%

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

(Thousands of Dollars)	2012			2011			2010
Current federal tax expense (benefit)	$	930		$	(1,540	)	$	3,754
Current state tax expense		2,216			1,573			1,536
Current change in unrecognized tax (benefit) expense		(69	)		(1,418	)		730
Deferred federal tax expense		25,089			30,251			19,133
Deferred state tax expense		1,890			4,105			2,288
Deferred change in unrecognized tax expense (benefit)		128			1,254			(707	)
Deferred investment tax credits		(626	)		(611	)		(622	)
Total income tax expense	$	29,558		$	33,614		$	26,112

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

(Thousands of Dollars)	2012			2011			2010
Deferred tax expense excluding items below	$	27,995		$	34,017		$	20,987
Amortization and adjustments to deferred income taxes on
income tax regulatory assets and liabilities		(837	)		1,644			(222	)
Tax expense allocated to other comprehensive income		(51	)		(51	)		(51	)
Deferred tax expense	$	27,107		$	35,610		$	20,714

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

(Thousands of Dollars)	2012		2011
Deferred tax liabilities:
Difference between book and tax bases of property	$	265,202	$	241,003
Regulatory assets		52,898		52,131
Employee benefits		16,862		21,013
Other		10,535		9,328
Total deferred tax liabilities	$	345,497	$	323,475
Deferred tax assets:
Environmental remediation	$	43,344	$	44,154
NOL carryforward		17,588		22,318
Tax credit carryforward		8,011		7,998
Regulatory liabilities		5,927		6,222
Deferred investment tax credits		5,766		5,705
Other		2,191		2,403
Total deferred tax assets	$	82,827	$	88,800
Net deferred tax liability	$	262,670	$	234,675

7. Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Wisconsin accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans.  NSP-Wisconsin is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Wisconsin accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Wisconsin employees.

Xcel Energy, which includes NSP-Wisconsin, offers various benefit plans to its employees.  Approximately 70 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2012, NSP-Wisconsin had 405 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2013.

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The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value.  The three levels in the hierarchy and examples of each level are as follows:

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

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

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

Pension Benefits

Xcel Energy, which includes NSP-Wisconsin, has several noncontributory, defined benefit pension plans that cover almost all employees.  Benefits are based on a combination of years of service, the employee’s average pay and social security benefits.  Xcel Energy Inc.’s and NSP-Wisconsin’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan.  The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants.  The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans.  The total obligations of the SERP and nonqualified plan as of Dec. 31, 2012 and 2011 were $39.4 million and $54.8 million, respectively, of which $0.6 million in each year was attributable to NSP-Wisconsin.   In 2012 and 2011, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $15.6 million and $5.7 million, respectively, of which amounts attributable to NSP-Wisconsin were immaterial. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the 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 pension cost determination assumes a forecasted mix of investment types over the long term.  Investment returns in 2012 were above the assumed level of 7.50 percent.  Investment returns in 2011 were below the assumed level of 8.00 percent while returns in 2010 were above the assumed level of 8.00 percent. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions.  In 2013, NSP-Wisconsin’s expected investment-return assumption is 7.25 percent.

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

The following table presents the target pension asset allocations for NSP-Wisconsin:

	2012			2011
Domestic and international equity securities		29	%		31	%
Long-duration fixed income securities		30			26
Short-to-intermediate term fixed income securities		12			14
Alternative investments		27			26
Cash		2			3
Total		100	%		100	%

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The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2012 and 2011:

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	7,956	$	-		$	-	$	7,956
Derivatives		-		390			-		390
Government securities		-		9,406			-		9,406
Corporate bonds		-		25,046			-		25,046
Asset-backed securities		-		-			749		749
Mortgage-backed securities		-		-			2,128		2,128
Common stock		3,977		-			-		3,977
Private equity investments		-		-			8,545		8,545
Commingled funds		-		76,398			-		76,398
Real estate		-		-			3,472		3,472
Securities lending collateral obligation and other		-		(1,521	)		-		(1,521	)
Total	$	11,933	$	109,719		$	14,894	$	136,546

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents.	$	6,604	$	-		$	-	$	6,604
Derivatives		-		296			-		296
Government securities		-		7,578			-		7,578
Corporate bonds		-		25,454			-		25,454
Asset-backed securities		-		-			1,578		1,578
Mortgage-backed securities		-		-			3,781		3,781
Common stock		3,693		-			-		3,693
Private equity investments		-		-			8,440		8,440
Commingled funds		-		64,520			-		64,520
Real estate		-		-			2,008		2,008
Securities lending collateral obligation and other		-		(2,604	)		-		(2,604	)
Total	$	10,297	$	95,244		$	15,807	$	121,348

The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2012, 2011 and 2010:

								Purchases,
			Net Realized		Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2012		Gains (Losses)		Gains (Losses)			Settlements, Net			Dec. 31, 2012
Asset-backed securities	$	1,578	$	197	$	(273	)	$	(753	)	$	749
Mortgage-backed securities		3,781		93		(112	)		(1,634	)		2,128
Private equity investments		8,440		945		(1,197	)		357			8,545
Real estate		2,008		1		328			1,135			3,472
Total	$	15,807	$	1,236	$	(1,254	)	$	(895	)	$	14,894

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									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2011
Asset-backed securities	$	1,367	$	121		$	(125	)	$	215		$	1,578
Mortgage-backed securities		5,984		55			(295	)		(1,963	)		3,781
Private equity investments		6,704		210			648			878			8,440
Real estate		3,746		(34	)		1,002			(2,706	)		2,008
Total	$	17,801	$	352		$	1,230		$	(3,576	)	$	15,807

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	2,357	$	173		$	(140	)	$	(1,023	)	$	1,367
Mortgage-backed securities		7,280		707			(717	)		(1,286	)		5,984
Private equity investments		4,053		(55	)		809			1,897			6,704
Real estate		3,294		(2	)		288			166			3,746
Total	$	16,984	$	823		$	240		$	(246	)	$	17,801

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:

(Thousands of Dollars)	2012			2011
Accumulated Benefit Obligation at Dec. 31	$	169,939		$	150,405
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	159,766		$	154,147
Service cost		4,568			4,271
Interest cost		7,765			8,031
Plan amendments		216			-
Actuarial loss		21,083			7,430
Benefit payments		(13,403	)		(14,113	)
Obligation at Dec. 31	$	179,995		$	159,766

(Thousands of Dollars)	2012			2011
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	121,348		$	123,541
Actual return on plan assets		16,079			5,474
Employer contributions		12,522			6,446
Benefit payments		(13,403	)		(14,113	)
Fair value of plan assets at Dec. 31	$	136,546		$	121,348

Funded Status of Plans at Dec. 31:	2012			2011
Funded status (a)	$	(43,449	)	$	(38,418	)

(a) Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.

(Thousands of Dollars)	2012		2011
NSP-Wisconsin Amounts Not Yet Recognized as Components of Net
Periodic Benefit Cost:
Net loss	$	99,338	$	89,730
Prior service cost		2,290		4,061
Total	$	101,628	$	93,791

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(Thousands of Dollars)	2012		2011
Amounts Related to the Funded Status of the Plans Have Been
Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	6,895	$	7,530
Noncurrent regulatory assets		94,733		86,261
Total	$	101,628	$	93,791
Measurement Date	Dec. 31, 2012		Dec. 31, 2011

	2012			2011
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		4.00	%		5.00	%
Expected average long-term increase in compensation level		3.75			4.00
Mortality table	RP 2000			RP 2000

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations.  These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans.  Required contributions were made in 2011 and 2012 to meet minimum funding requirements.

The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2013:

· In January 2013, contributions of $191.5 million were made across four of Xcel Energy’s pension plans, of which $11.3 million was attributable to NSP-Wisconsin;

· In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $12.5 million was attributable to NSP-Wisconsin;

· In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $6.4 million was attributable to NSP-Wisconsin;

· For future years, Xcel Energy and NSP-Wisconsin anticipate contributions will be made as necessary.

Plan Amendments — Xcel Energy, which includes NSP-Wisconsin, amended the plan in 2012 to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans.  Xcel Energy and NSP-Wisconsin also modified the benefit formula for nonbargaining new hires beginning in 2012 to a reduced benefit level.

Benefit Costs —The components of NSP-Wisconsin’s net periodic pension cost were:

(Thousands of Dollars)	2012			2011			2010
Service cost	$	4,568		$	4,271		$	4,260
Interest cost		7,765			8,031			8,311
Expected return on plan assets		(10,489	)		(11,484	)		(11,800	)
Amortization of prior service cost		1,771			1,895			1,629
Amortization of net loss		6,004			4,070			2,463
Net periodic pension cost	$	9,619		$	6,783		$	4,863

Significant Assumptions Used to Measure Costs:	2012			2011			2010
Discount rate		5.00	%		5.50	%		6.00	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		7.50			8.00			8.00

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In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs.  Amounts allocated to NSP-Wisconsin were $1.8 million, $1.3 million and $1.0 million in 2012, 2011 and 2010, respectively.  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 2013 pension cost calculations is 7.25 percent.  The cost calculation uses a market-related valuation of pension assets.  Xcel Energy, including NSP-Wisconsin, uses a calculated value method to determine the market-related value of the plan assets.  The market-related value begins with the fair market value of assets as of the beginning of the year.  The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.  As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes NSP-Wisconsin, maintains 401(k) and other defined contribution plans that cover substantially all employees.  The contributions to these plans for NSP-Wisconsin were approximately $1.2 million in 2012, $1.1 million in 2011 and $1.0 million in 2010.

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Wisconsin, has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees.  The former NSP, which includes NSP-Wisconsin, 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.

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

Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs.  Also, a portion of the assets contributed on behalf of nonbargaining 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.

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

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2012 and 2011:

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	123	$	-		$	-	$	123
Government securities		-		99			-		99
Insurance contracts		-		67			-		67
Corporate bonds		-		59			-		59
Asset-backed securities		-		-			1		1
Mortgage-backed securities		-		-			54		54
Commingled funds		-		307			-		307
Other		-		(63	)		-		(63	)
Total	$	123	$	469		$	55	$	647

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	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	101	$	-		$	-	$	101
Derivatives		-		23			-		23
Government securities		-		116			-		116
Corporate bonds		-		108			-		108
Asset-backed securities		-		-			14		14
Mortgage-backed securities		-		-			48		48
Preferred stock		-		1			-		1
Commingled funds		-		355			-		355
Securities lending collateral obligation and other		-		(20	)		-		(20	)
Total	$	101	$	583		$	62	$	746

The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2012, 2011 and 2010:

								Purchases,
			Net Realized			Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2012		Gains (Losses)			Gains (Losses)		Settlements, Net			Dec. 31, 2012
Asset-backed securities	$	14	$	-		$	3	$	(16	)	$	1
Mortgage-backed securities		48		(1	)		6		1			54
Total	$	62	$	(1	)	$	9	$	(15	)	$	55

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, Net		Dec. 31, 2011
Asset-backed securities	$	6	$	-		$	(2	)	$	10	$	14
Mortgage-backed securities		45		(3	)		6			-		48
Total	$	51	$	(3	)	$	4		$	10	$	62

								Purchases,
			Net Realized			Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)		Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	30	$	(1	)	$	4	$	(27	)	$	6
Mortgage-backed securities		168		(2	)		16		(137	)		45
Total	$	198	$	(3	)	$	20	$	(164	)	$	51

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:

(Thousands of Dollars)	2012			2011
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	22,127		$	20,753
Service cost		20			17
Interest cost		1,075			1,144
Medicare subsidy reimbursements		189			180
Early Retiree Reinsurance Program proceeds shared with retirees		-			298
Plan amendments		(3,440	)		-
Plan participants’ contributions		893			1,059
Actuarial loss		1,486			2,425
Benefit payments		(2,918	)		(3,749	)
Obligation at Dec. 31	$	19,432		$	22,127

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(Thousands of Dollars)	2012			2011
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	746		$	992
Actual return (loss) on plan assets		3			(1	)
Plan participants’ contributions		893			1,059
Employer contributions		1,923			2,445
Benefit payments		(2,918	)		(3,749	)
Fair value of plan assets at Dec. 31	$	647		$	746

(Thousands of Dollars)	2012			2011
Funded Status of Plans at Dec. 31:
Funded status	$	(18,785	)	$	(21,381	)
Current liabilities		(943	)		(1,281	)
Noncurrent liabilities		(17,842	)		(20,100	)
Net postretirement amounts recognized on consolidated balance sheets	$	(18,785	)	$	(21,381	)

(Thousands of Dollars)	2012			2011
NSP-Wisconsin Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	13,730		$	12,683
Prior service credit		(3,538	)		(112	)
Transition obligation		1			172
Total	$	10,193		$	12,743

(Thousands of Dollars)	2012		2011
Amounts Related to the Funded Status of the Plans Have Been Recorded as
Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	433	$	697
Noncurrent regulatory assets		9,760		12,046
Total	$	10,193	$	12,743
Measurement Date	Dec. 31, 2012		Dec. 31, 2011

	2012			2011
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		4.10	%		5.00	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate - initial		7.50	%		6.31	%

Effective Dec. 31, 2012, the initial medical trend rate was increased from 6.3 percent to 7.5 percent.  The ultimate trend assumption was reduced from 5.0 percent to 4.5 percent.  The period until the ultimate rate is reached is seven years.  Xcel Energy Inc. and NSP-Wisconsin base the 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 the retiree medical plan.

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

	One Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	1,712	$	(1,376	)
Service and interest components		126		(102	)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans.  Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously.  Xcel Energy, which includes NSP-Wisconsin, contributed $47.1 million and $49.0 million during 2012 and 2011, of which $1.9 million and $2.4 million were attributable to NSP-Wisconsin.  Xcel Energy expects to contribute approximately $21.8 million during 2013, of which $1.6 million is attributable to NSP-Wisconsin.

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Plan Amendments — The 2012 decrease of the projected Xcel Energy and NSP-Wisconsin postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator.

Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit cost were:

(Thousands of Dollars)	2012			2011			2010
Service cost	$	20		$	17		$	15
Interest cost		1,075			1,144			1,234
Expected return on plan assets		(50	)		(74	)		(103	)
Amortization of transition obligation		171			171			171
Amortization of prior service cost		(14	)		(14	)		(14	)
Amortization of net loss		486			366			342
Net periodic postretirement benefit cost	$	1,688		$	1,610		$	1,645

Significant Assumptions Used to Measure Costs:	2012			2011			2010
Discount rate		5.00	%		5.50	%		6.00	%
Expected average long-term rate of return on assets		6.75			7.50			7.50

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs.

Projected Benefit Payments

The following table lists NSP-Wisconsin’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
2013	$	16,388	$	1,598	$	8	$	1,590
2014		15,152		1,468		11		1,457
2015		16,117		1,459		9		1,450
2016		14,986		1,433		8		1,425
2017		14,664		1,365		3		1,362
2018-2022		69,528		6,286		16		6,270

Multiemployer Plans

NSP-Wisconsin contributes to several union multiemployer pension plans, none of which are individually significant.  These plans provide pension benefits to certain union employees, including electrical workers and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Wisconsin sponsored pension plans.  Contributing to these types of plans creates risk that differs from providing benefits under NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2012, 2011 and 2010.  There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented:

(Thousands of Dollars)	2012		2011		2010
Multiemployer plan contributions:
Pension	$	163	$	169	$	170
Total	$	163	$	169	$	170

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8.  Other Income, Net

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

(Thousands of Dollars)	2012			2011			2010
Interest income	$	736		$	324		$	1,190
Other nonoperating income		129			67			459
Insurance policy expense		(389	)		(283	)		(384	)
Other nonoperating expense		-			(10	)		-
Other income, net	$	476		$	98		$	1,265

9. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Derivative Instruments Fair Value Measurements

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

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

At Dec. 31, 2012, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged transactions impact earnings.

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for each of the years ended Dec. 31, 2012, 2011 and 2010.

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

The following table details the gross notional amounts of commodity forwards and options at Dec. 31, 2012 and 2011:

(Amounts in Thousands) (a) (b)	Dec. 31, 2012		Dec. 31, 2011
MMBtu of natural gas		53		1,393

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

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

Consideration of Credit Risk and Concentrations — NSP-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment, as well as an assessment of the impact of NSP-Wisconsin’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

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

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

(Thousands of Dollars)	2012			2011			2010
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(514	)	$	(590	)	$	(666	)
After-tax net realized losses on derivative transactions reclassified into earnings		77			76			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(437	)	$	(514	)	$	(590	)

During the years ended Dec. 31, 2012, 2011 and 2010, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.4 million, $3.6 million and $3.4 million, respectively, recognized as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Natural gas commodity derivatives settlement losses of $2.9 million, $2.9 million and $1.1 million were recognized during each of the years ended Dec. 31, 2012, 2011 and 2010, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2012, 2011 and 2010.

Recurring Fair Value Measurements — The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s liabilities measured at fair value on a recurring basis:

	Dec. 31, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (a)		Total (b)
Current derivative liabilities
Natural gas commodity	$	-	$	11	$	-	$	11	$	-	$	11

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	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (a)		Total (b)
Current derivative liabilities
Natural gas commodity	$	418	$	2,096	$	-	$	2,514	$	-	$	2,514

(a) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-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) Included in other current liabilities balance of $11.8 million and $13.9 million at Dec. 31, 2012 and 2011, respectively, in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2012 and 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2012				2011
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,563	$	576,353	$	369,369	$	474,356

The fair value of NSP-Wisconsin’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of Dec. 31, 2012 and 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

10. Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

Base Rate

NSP-Wisconsin – 2012 Electric and Gas Rate Case— In June 2012, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service, effective Jan. 1, 2013.  NSP-Wisconsin requested an overall increase in annual electric rates of $39.1 million, or 6.7 percent, and an increase in natural gas rates of $5.3 million, or 4.9 percent.

The electric rate filing was based on a 2013 forecast test year, a ROE of 10.40 percent, an equity ratio of 52.50 percent and an average 2013 electric rate base of approximately $788.6 million.  The natural gas rate request was solely due to a proposal to recover the initial costs associated with the environmental cleanup of the Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) in Ashland, Wis.

In December 2012, the PSCW approved an electric rate increase of approximately $35.5 million, or 6.1 percent, based on a 10.4 percent ROE and an equity ratio of 52.50 percent.  The PSCW also approved a natural gas rate increase of $2.7 million, or 2.5 percent, to begin recovering costs associated with the cleanup of the Ashland site.  Final rates were implemented on Jan. 1, 2013.

11.  Commitments and Contingencies

Commitments

Capital Commitments — NSP-Wisconsin has made commitments in connection with a portion of its projected capital expenditures.  NSP-Wisconsin’s capital commitments primarily relate to one major project, CapX2020.

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CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including NSP System that has proposed several groups of transmission projects to be complete by 2020.  Group 1 project investments consist of four transmission lines.  Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015.  NSP System’s investment depends on the routes and configurations approved by affected state commissions and on the allocation of costs borne by other participating utilities in the upper Midwest.

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 2013 and 2029.  In addition, NSP-Wisconsin is 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 utilizes deferred accounting treatment and seeks future rate recovery when fuel costs exceed the amount included in rates by more than 2 percent on an annual basis.

The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2012 are as follows:

(Millions of dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2013	$	6.3	$	10.3	$	13.2
2014		1.2		0.3		11.3
2015		0.7		0.3		10.7
2016		0.7		0.3		10.7
2017		0.7		0.3		8.6
Thereafter		4.6		-		20.5
Total (a)	$	14.2	$	11.5	$	75.0

(a) Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs.

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

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

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

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

(Thousands of Dollars)	Dec. 31, 2012		Dec. 31, 2011
Current assets	$	357	$	270
Property, plant and equipment, net		2,599		2,727
Other noncurrent assets		105		102
Total assets	$	3,061	$	3,099
Current liabilities	$	1,388	$	1,389
Mortgages and other long-term debt payable		617		640
Other noncurrent liabilities		39		43
Total liabilities	$	2,044	$	2,072

Leases— NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business.  These leases, primarily for office space, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $1.1 million, $1.4 million and $1.4 million for 2012, 2011 and 2010, respectively.

Future commitments under operating leases are:

(Millions of Dollars)
2013	$	0.8
2014		0.8
2015		0.8
2016		0.8
2017		0.9
Thereafter		9.3
Total	$	13.4

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

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $12.6 billion under the Price-Anderson amendment to the Atomic Energy Act.  NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies.  The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident.  NSP-Minnesota is subject to assessments of up to $117.5 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States.  The maximum funding requirement is $17.5 million per reactor during any one year.  These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes.  The NRC’s last adjustment was effective April 2010.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL).  The coverage limits are $2.25 billion for each of NSP-Minnesota’s two nuclear plant sites.  NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units.  Premiums are expensed over the policy term.  All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds.  Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.  However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.5 million for business interruption insurance and $35.8 million for property damage insurance if losses exceed accumulated reserve funds.

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Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program.  NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement.  The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee.  The guarantee contains no recourse provisions and requires no collateral.

The following table presents the guarantee issued and outstanding for NSP-Wisconsin:

(Millions of Dollars)	Guarantee Amount		Current Exposure		Term or Expiration Date		Triggering Event Requiring Performance
Guarantee of customer loans for the Farm Rewiring Program	$	1.0	$	0.4		2017	(a)

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

Environmental Contingencies

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

Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment.  NSP-Wisconsin may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations, including sites of former MGPs operated by NSP-Wisconsin, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Wisconsin is alleged to be a PRP that sent hazardous materials and wastes to that site.

MGP Sites

Ashland MGP Site — NSP-Wisconsin has been named a PRP for contamination at a site in Ashland, Wis.  The Ashland site includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The EPA issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site.  In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site.  The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site.  As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas.  The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff.  The second area includes the Sediments.

In October 2012, a settlement among the EPA, the WDNR, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin.  This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area.  Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site.  The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million.  The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments.  As part of the settlement, NSP-Wisconsin will convey approximately 1,390 acres of land to the State of Wisconsin.  Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and will continue into 2013.

Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing.  The EPA’s ROD for the Ashland site includes estimates that the cost of the preferred remediation related to the Sediments is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.

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In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site.  Trial for this matter has been scheduled for June 2014.

At Dec. 31, 2012 and 2011, NSP-Wisconsin had recorded a liability of $103.7 million and $104.3 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $20.1 million and $26.6 million, respectively, was considered a current liability.  NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change.  NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site.  Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

Historically, NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.  The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by 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 retail rate case process.  Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period.  The PSCW has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

In a recent rate case decision, however, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site.  In December 2012, the PSCW granted an exception to its existing policy at the request of NSP-Wisconsin.  The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a 3 percent carrying cost to the unamortized regulatory asset and to recover these carrying costs from natural gas customers. Implementation of this exception will mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin for a longer amortization.

Other MGP Sites — NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited.  NSP-Wisconsin has identified three sites, where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation.  At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation.  NSP-Wisconsin anticipates that the majority of the remediation at these sites will continue through at least 2014.  NSP-Wisconsin had accrued $2.5 million and $3.3 million for all of these sites at Dec. 31, 2012 and 2011, respectively.  There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred.  NSP-Wisconsin anticipates that any amounts spent will be fully recovered from customers.

Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed.  NSP-Wisconsin has recorded an estimate for final removal of the asbestos as an ARO.  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 not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Environmental Requirements

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare.  In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold.  NSP-Wisconsin is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Wisconsin’s power plants.

GHG New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the EPA proposed a GHG NSPS for newly constructed power plants.  The proposal requires that CO2 emission rates be equal to a natural gas combined-cycle plant, even if the plant is coal-fired.  The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and that installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the CAA.  It is not known when the EPA will propose new standards for existing sources.

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CSAPR — In 2011, the EPA issued the CSAPR to address long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States, including Wisconsin.  The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule.  The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the CSAPR and remanded it back to the EPA.  The D.C. Circuit also stated that the EPA must continue administering the CAIR pending adoption of a valid replacement.  In October 2012, the EPA, as well as state and local governments and environmental advocates, petitioned the D.C. Circuit to rehear the CSAPR appeal.  In January 2013, the D.C. Circuit denied all requests for rehearing.  It is not yet known whether the D.C. Circuit’s decision will be appealed, or how the EPA might approach a replacement rule.  Therefore, it is not known what requirements may be imposed in the future.

If the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, NSP-Wisconsin expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  NSP-Wisconsin purchased allowances in 2012 and plans to continue to purchase allowances in 2013 to comply with the CAIR.  At Dec. 31, 2012, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date.  NSP-Wisconsin plans to cease coal combustion at Bay Front Unit 5 before the MATS compliance date, therefore the MATS rule will not be applicable.  Bay Front Unit 5 will become a natural gas-fired unit subject to the Industrial Boiler (IB) MACT.  The IB MACT requirements for Bay Front Unit 5 are not expected to have a material impact on results of operations, financial position or cash flows.

IB MACT Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2.  The capital cost to install controls to meet the requirements in the final reconsidered rule is estimated to be $9.0 million per unit, which are targeted for completion in 2014.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM.  In areas where NSP-Wisconsin operates power plants, current monitored air concentrations are below the level of the final annual primary standard.  The EPA is expected to designate non-compliant locations by December 2014.  States would then study the sources of the nonattainment and make emission reduction plans to attain the standards.  It is not possible to evaluate the impact of this regulation further until the final designations have been made.

Federal Clean Water Act (CWA) Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species.  In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office.  The proposed rule is expected to be finalized in July 2013.  It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.

Proposed Coal Ash Regulation — NSP-Wisconsin’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste.  In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste.  Coal ash is currently exempt from hazardous waste regulation.  NSP-Wisconsin’s costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste.  The EPA has not announced a planned date for a final rule.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

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Asset Retirement Obligations

Recorded AROs — AROs have been recorded for plant related to steam production, electric transmission and distribution and natural gas transmission and distribution.  The steam production obligation includes asbestos.  The asbestos recognition associated with the steam production includes certain plants.  This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  The electric transmission and distribution ARO consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps.  These electric and natural gas assets have numerous 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 NSP-Wisconsin’s AROs is shown in the tables below for the years ended Dec. 31, 2012 and 2011, respectively:

	Beginning						Revisions		Ending
	Balance		Liabilities				to Prior		Balance
(Thousands of Dollars)	Jan. 1, 2012		Recognized		Accretion		Estimates		Dec. 31, 2012 (a)
Electric plant
Steam production asbestos	$	-	$	1,962	$	-	$	-	$	1,962
Electric transmission and distribution		357		-		13		633		1,003
Natural gas plant
Gas transmission and distribution		67		-		4		-		71
Total liability (b)	$	424	$	1,962	$	17	$	633	$	3,036

	Beginning						Revisions		Ending
	Balance		Liabilities				to Prior		Balance
(Thousands of Dollars)	Jan. 1, 2011		Recognized		Accretion		Estimates		Dec. 31, 2011 (a)
Electric plant
Electric transmission and distribution	$	67	$	-	$	3	$	287	$	357
Natural gas plant
Gas transmission and distribution		63		-		4		-		67
Total liability (b)	$	130	$	-	$	7	$	287	$	424

(a) There were no ARO liabilities settled during the 12 months ended Dec. 31, 2012 or 2011.

(b) Included in the other long-term liabilities balance in the consolidated balance sheets.

In 2012 and 2011, NSP-Wisconsin revised electric transmission and distribution AROs due to revised estimated cash flows.  Additionally, in 2012, an ARO was recorded to reflect the expected costs with asbestos abatement at certain steam production facilities.

Removal Costs — NSP-Wisconsin records a regulatory liability for plant removal costs of steam and other generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO removal obligations is not required.  However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.  These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities.  Given the long periods over which the amounts were accrued and the changing of rates through time, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities.  Removal costs as of Dec. 31, 2012 and 2011 were $114 million and $109 million, respectively.

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Legal Contingencies

NSP-Wisconsin is involved in various litigation matters that are being defended and handled in the ordinary course of business.  The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.  Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.  In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.  For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Wisconsin’s financial statements.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

Environmental Litigation

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 the U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of NSP-Wisconsin, and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In October 2012, the Ninth Circuit affirmed the U.S. District Court’s dismissal and subsequently rejected plaintiffs’ request for rehearing.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million.  Although Xcel Energy Inc. believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc. and NSP-Wisconsin.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  Although Xcel Energy Inc. believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

12.  Regulatory Assets and Liabilities

NSP-Wisconsin’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities.  If changes in the utility industry or the business of NSP-Wisconsin no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

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The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2012 and Dec. 31, 2011 are:

	See		Remaining
(Thousands of Dollars)	Notes		Amortization Period	Dec. 31, 2012				Dec. 31, 2011
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Environmental remediation costs		1, 11	Various	$	2,521	$	109,162	$	-	$	108,181
Pension and retiree medical obligations (a)		7	Various		7,328		104,426		8,197		98,045
Recoverable deferred taxeson AFUDC
recorded in plant		1	Plant lives		-		10,458		-		9,630
Losses on reacquired debt		4	Term of related debt		800		6,538		843		7,338
State commission adjustments		1	Plant lives		339		7,533		277		4,506
Contract valuation adjustments (b)		1, 9	Term of related contract		11		-		2,515		-
Conservation programs		1	Less than one year		691		-		2,301		-
Deferred income tax adjustment		1, 6	Typically plant lives		-		1,974		-		1,868
Recoverable purchased natural gas costs			Less than one year		358		-		-		-
Other			Various		-		368		-		342
Total regulatory assets				$	12,048	$	240,459	$	14,133	$	229,910

(a) Includes the non-qualified pension plan.

(b) Includes valuation adjustments on natural gas commodity purchases.

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2012 and Dec. 31, 2011 are:

	See		Remaining
(Thousands of Dollars)	Notes		Amortization Period	Dec. 31, 2012				Dec. 31, 2011
Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
Plant removal costs		11	Plant lives	$	-	$	113,949	$	-	$	108,850
DOE settlement		11	Less than one year		5,628		-		14,484		-
Investment tax credit deferrals		1, 6	Various		-		9,626		-		9,525
Conservation programs		1	Less than one year		73		-		-		-
Deferred electric energy costs		1	Less than one year		134		-		1,869		-
Other			Various		251		171		256		812
Total regulatory liabilities				$	6,086	$	123,746	$	16,609	$	119,187

At Dec. 31, 2012, approximately $0.4 million of NSP-Wisconsin's regulatory assets represented past expenditures not currently earning a return.  This amount primarily includes recoverable purchased natural gas costs.

13. Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker.  NSP-Wisconsin evaluates performance based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each reportable segment.

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

· NSP-Wisconsin’s regulated electric utility segment generates electricity which is transmitted and distributed 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.

· 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.

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

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

The accounting policies of the segments are the same as those described in Note 1.

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2012
Operating revenues	$	757,565	$	103,100	$	1,177		$	-		$	861,842
Intersegment revenues		355		727		-			(1,082	)		-
Total revenues	$	757,920	$	103,827	$	1,177		$	(1,082	)	$	861,842
Depreciation and amortization	$	59,768	$	9,251	$	215		$	-		$	69,234
Interest charges and financing cost		20,303		2,554		80			-			22,937
Income tax expense		27,164		2,113		281			-			29,558
Net income		45,377		3,094		1,480			-			49,951
2011
Operating revenues	$	755,136	$	119,447	$	1,207		$	-		$	875,790
Intersegment revenues		405		1,581		-			(1,986	)		-
Total revenues	$	755,541	$	121,028	$	1,207		$	(1,986	)	$	875,790
Depreciation and amortization	$	58,800	$	9,599	$	175		$	-		$	68,574
Interest charges and financing cost		21,181		2,675		137			-			23,993
Income tax expense (benefit)		32,656		1,995		(1,037	)		-			33,614
Net income		47,093		2,964		949			-			51,006
2010
Operating revenues	$	708,179	$	118,076	$	1,036		$	-		$	827,291
Intersegment revenues		360		1,122		-			(1,482	)		-
Total revenues	$	708,539	$	119,198	$	1,036		$	(1,482	)	$	827,291
Depreciation and amortization	$	54,414	$	9,037	$	218		$	-		$	63,669
Interest charges and financing cost		20,738		2,597		143			-			23,478
Income tax expense (benefit)		24,819		1,836		(543	)		-			26,112
Net income		37,773		3,325		1,651			-			42,749

14. Related Party Transactions

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

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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)	2012		2011		2010
Operating revenues:
Electric	$	125,344	$	124,334	$	116,312
Operating expenses:
Purchased power		405,016		399,649		377,518
Transmission expense		44,942		40,870		38,558
Natural gas purchased for resale		116		98		163
Other operating expenses - paid to Xcel Energy Services Inc.		54,137		54,885		52,826
Interest expense		22		48		56

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

	2012				2011
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	-	$	26,632	$	-	$	18,003
PSCo		-		71		-		112
SPS		-		4		-		-
Other subsidiaries of Xcel Energy Inc.		586		4,849		-		5,170
	$	586	$	31,556	$	-	$	23,285

15.  Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
Operating revenues	$	223,799	$	194,173	$	226,475	$	217,395
Operating income		28,914		14,348		40,735		15,869
Net income		14,878		5,742		22,200		7,131
	Quarter Ended
(Thousands of Dollars)	March 31, 2011		June 30, 2011		Sept. 30, 2011		Dec. 31, 2011
Operating revenues	$	238,108	$	198,850	$	224,468	$	214,364
Operating income		29,897		20,115		39,032		18,464
Net income		14,643		8,478		19,973		7,912

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

None.

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Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Wisconsin maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Dec. 31, 2012, 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, 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, 2012 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 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 independent registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by NSP-Wisconsin’s independent registered public accounting firm pursuant to the rules of the SEC 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 and Related Transactions, and Director Independence

Item 14 — Principal Accountant Fees and Services

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2013 Annual Meeting of Shareholders, which is incorporated by reference.

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PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2012
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2012, 2011 and 2010.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2012, 2011 and 2010.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2012, 2011 and 2010.
	Consolidated Balance Sheets — As of Dec. 31, 2012 and 2011.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2012, 2011 and 2010.
3.	Exhibits
	*	Indicates incorporation by reference
	+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
	t	Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
3.01*	Amended and restated articles of incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) Jan. 21, 2004).
3.02*	By-Laws of NSP-Wisconsin as amended June 3, 2008 (Exhibit 3.02 to Form 10-Q (file no. 001-03140) Aug. 4, 2008).
4.01*	Supplemental and Restated Trust Indenture dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust company, providing for the issuance of First Mortgage Bonds (Exhibit 4.01 to Registration Statement 33-39831).
4.02*	Supplemental Trust Indenture dated April 1, 1991 (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
4.03*	Supplemental Trust Indenture dated Dec. 1, 1996 (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
4.04*	Trust Indenture dated Sept. 1, 2000, between NSP-Wisconsin and Firstar Bank, NA as Trustee  (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
4.05*	Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and US Bank NA, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.06*	Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank NA, as successor Trustee, creating $200 million principal amount of 6.375 percent First Mortgage Bonds, Series due Sept. 1, 2038 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Sept. 3, 2008 (file no. 001-03140)).
4.07*	Supplemental Indenture dated as of Oct. 1, 2012 between NSP-Wisconsin and U.S. Bank NA, as successor Trustee, creating $100 million principal amount of 3.700 percent First Mortgage Bonds, Series due Oct. 1, 2042 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Oct. 10, 2012 (file no. 001-03140)).
10.01*+	Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	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).
10.04*+	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).
10.05*+	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).
10.06*	Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP- Minnesota (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.07*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.08*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).

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10.09*+	Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy  (file no. 001-03034) dated April 6, 2010).
10.10*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.11*+	Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.12*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.13*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.14*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.15*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.16*	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.17*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.18*+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.19*	Amended and Restated Credit Agreement, dated as of July 27, 2012 among NSP-Wisconsin, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.05 to Xcel Energy Inc.’s Form 8-K, dated July 27, 2012 (file no. 001-03034)).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101t	The following materials from NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flow, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) Notes to Condensed Consolidated Financial Statements, and (vii) document and entity information.

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SCHEDULE II

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2012, 2011 AND 2010

(amounts in thousands)

			Additions
	Balance at Jan. 1		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions from Reserves (b)		Balance at Dec. 31
Allowance for bad debts:
2012	$	4,766	$	3,329	$	1,310	$	5,072	$	4,333
2011		4,262		3,842		1,241		4,579		4,766
2010		4,709		3,294		1,207		4,948		4,262

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off.

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SIGNATURES

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

	NORTHERN STATES POWER COMPANY
	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Senior Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)
Feb. 25, 2013

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

/s/ MARK E. STOERING	/s/ BENJAMIN G.S. FOWKE III
Mark E. Stoering	Benjamin G.S. Fowke III
President, Chief Executive Officer and Director	Chairman and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ JEFFREY S. SAVAGE
Teresa S. Madden	Jeffrey S. Savage
Senior Vice President, Chief Financial Officer and Director	Vice President and Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ DAVID M. SPARBY
David M. Sparby
Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

NSP-Wisconsin has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

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