10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

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 ý 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 ý 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. ý 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). ý 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. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

As of Feb. 24, 2014, 933,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2014 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 Instructions 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
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	8
Fuel Sources	8
Renewable Energy Sources	9
Summary of Recent Federal Regulatory Developments	10
Electric Operating Statistics	12
NATURAL GAS UTILITY OPERATIONS	13
Public Utility Regulation	13
Capability and Demand	14
Natural Gas Supply and Costs	14
Natural Gas Operating Statistics	15
GENERAL	15
ENVIRONMENTAL MATTERS	16
EMPLOYEES	16
Item 1A — Risk Factors	16
Item 1B — Unresolved Staff Comments	26
Item 2 — Properties	26
Item 3 — Legal Proceedings	27
Item 4 — Mine Safety Disclosures	27
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6 — Selected Financial Data	27
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	30
Item 8 — Financial Statements and Supplementary Data	31
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A — Controls and Procedures	72
Item 9B — Other Information	73
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	73
Item 11 — Executive Compensation	73
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	73
Item 13 — Certain Relationships and Related Transactions, and Director Independence	73
Item 14 — Principal Accountant Fees and Services	73
PART IV
Item 15 — Exhibits, Financial Statement Schedules	73
SIGNATURES	77

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 electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and 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
CFTC	Commodity Futures Trading Commission
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
PGA	Purchased gas adjustment
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
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
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
LNG	Liquefied natural gas

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MACT	Maximum Achievable Control Technology
MGP	Manufactured gas plant
MISO	Midcontinent Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
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
NSPS	New source performance standard
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
ROFR	Right of first refusal
RPS	Renewable portfolio standards
RSG	Revenue sufficiency guarantee
RTO	Regional Transmission Organization
ROFR	Right of first refusal
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 a 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.  NSP-Wisconsin purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in this service territory.  NSP-Wisconsin provides electric utility service to approximately 253,000 customers and natural gas utility service to approximately 110,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2013.  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 the following industries:  food products, paper, allied products, oil and gas extraction and sand mining.  For small commercial and industrial customers, significant electric retail sales include the following industries:  grocery and dining establishments, educational services, and food products.  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 14 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 four core objectives: driving operational excellence; providing options and solutions to customers; investing for the future; and enhancing engagement with employees, customers, shareholders, communities and policy makers.  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. In recent years, NSP-Wisconsin has been submitting rate filings each year.

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 under-collection or over-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. Fuel cost under-collections that exceed the two percent annual tolerance band for a calendar year may not be recovered if the utility earnings for that year exceed the authorized ROE.

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NSP-Wisconsin’s wholesale electric rate schedules included a FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.  However, as of Jan. 1, 2013, NSP-Wisconsin no longer served any wholesale municipal electric customers.  Rates for wholesale municipal services provided in 2012 were subject to a final true-up, which was completed in 2013.

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.

2013 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for 2013 exceeded the levels authorized in Wisconsin retail rates, and were outside the two percent annual tolerance band established by the PSCW pursuant to the Wisconsin fuel cost recovery rules.  Extended outages at two base load generation plants and higher than forecast prices in the MISO market were the primary causes of higher electric fuel costs. Rate recovery of the deferred amount is contingent on review and approval by the PSCW after opportunity for a hearing, and the earnings test based on NSP-Wisconsin’s 2013 authorized ROE of 10.4 percent.  NSP-Wisconsin has reviewed its 2013 fuel cost under-recovery, and has completed the earnings test, and has determined that it would be ineligible for rate recovery of any 2013 deferred fuel costs.  Accordingly, NSP-Wisconsin has expensed all 2013 fuel costs.

Wisconsin Energy Efficiency Program— In Wisconsin, the primary energy efficiency program is funded by the state’s utilities, but operated by independent contractors subject to oversight by the PSCW and the utilities. In 2013, NSP-Wisconsin was allocated approximately $8.3 million of the statewide program costs. NSP-Wisconsin recovers these costs in rates charged to Wisconsin retail customers.

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 2014, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2011	2012	2013	2014 Forecast
NSP System	9,792	9,475	9,524	9,212

The peak demand for the NSP System typically occurs in the summer. The 2013 uninterrupted system peak demand for the NSP System occurred on Aug. 26, 2013. 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 2013 peak demand includes the effect of warmer weather partially offset by the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin and also reflects the impact of two large commercial and industrial customers at NSP-Minnesota that have ceased operations. These two large customers represented 1.3 percent, 0.4 percent, and zero percent of NSP System sales in 2011, 2012, and 2013 respectively. The 2014 forecast assumes normal peak day weather.

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.

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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 March 2013, the MPUC approved NSP-Minnesota’s 2011-2025 Resource Plan and ordered a competitive acquisition process be conducted with the goal of adding approximately 500 MW of generation to the NSP System by 2019.  Bid proposals were received in April 2013.

In September 2013, NSP-Minnesota recommended a self-build, 215 MW natural gas combustion turbine at the Black Dog site and a PPA with either Calpine’s Mankato combined cycle natural gas project or Invenergy’s Cannon Falls combustion turbine natural gas project. In October 2013, the DOC recommended the MPUC approve NSP-Minnesota’s proposal.

On Dec. 31, 2013, the ALJ recommended the MPUC select a combination of a 100 MW solar proposal by Geronimo Energy, LLC and capacity credits offered by Great River Energy.

In January 2014, NSP-Minnesota filed exceptions to the ALJ’s report which supported NSP-Minnesota’s original proposal, reiterated its commitment to meeting the solar mandate and made the following points:

• The ALJ’s report focused on meeting a portion of the solar mandate even though the docket was designed to meet our resource need;

• Solar acquisition to meet the solar mandate should be conducted separately to encourage competition among solar developers;

• One or more gas fueled plants should be selected because they are large enough to meet the range of reasonably expected need, are least cost, and comply with environmental regulations; and

• Resource need uncertainty should be addressed through contract options to delay or cancel resources.

The MPUC is expected to make its selection determination in March 2014.

In the first half of 2013, NSP-Minnesota also issued a request for proposal for cost effective wind generation. In the summer of 2013, NSP-Minnesota filed a petition with the MPUC and the NDPSC seeking approval of four wind generation projects. The projects are as follows:

• A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota, which is expected to be operational by October 2015;

• A 150 MW ownership project for the Border Winds wind farm in North Dakota, which is expected to be operational by 2015;

• A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and

• A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.

In October 2013, the four wind projects were approved by the MPUC. A NDPSC decision is anticipated in early 2014. The feasibility of the Border Winds and Pleasant Valley projects are also dependent on the finalization of estimated transmission costs, which MISO is expected to determine in the first half of 2014.

NSP-WisconsinCapX2020 CPCN — The PSCW issued a CPCN for the Wisconsin portion of the Hampton, Minn. to La Crosse, Wis. project in May 2012.  The Wisconsin route is approximately 50 miles of new transmission line with an estimated cost of $211 million.  Construction on the Wisconsin terminus of the line, the Briggs Road Substation, began in mid-2013 and construction on the Wisconsin portion of the line is anticipated to begin in mid-2014. The line is expected to go into service in 2015.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line— In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, also known as the Badger Coulee line, would run between 159 and 182 miles, and cost between $514 and $552 million, depending upon the route ultimately approved by the PSCW. NSP-Wisconsin’s share of the investment is estimated to be between $230 and $247 million. The cost estimates are based on a projected 2018 in-service year. In December 2011, MISO determined the line to be an MVP project, and as such, eligible for cost sharing under MISO’s MVP tariff.

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In November 2013, the PSCW found the application to be incomplete. A finding of incompleteness is a typical step for large transmission projects before the PSCW. In February 2014, NSP-Wisconsin and ATC submitted additional information in response to the PSCW’s determination. The PSCW is expected to issue a decision on the CPCN application in the first half of 2015. If approved, NSP-Wisconsin and ATC anticipate beginning construction on the line in mid-2016, with completion by late-2018.

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 (a)				Nuclear				Natural Gas				Weighted Average Owned Fuel Cost
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent
2013	$	2.20	49	%	$	0.95	40	%	$	5.08	11	%	$	2.03
2012	2.13		47		0.90		42		4.21		11		1.88
2011	2.06		55		0.89		40		6.56		5		1.82

^(a)  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, 2013 and 2012 were approximately 34 and 39 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 2013 and 2012, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.3 million tons and 7.2 million tons, respectively.  The estimated coal requirements for 2014 are approximately 9.2 million tons. The coal requirements estimated for 2014 are higher primarily due to Sherco Unit 3 being placed back in service.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 94 percent of their estimated coal requirements in 2014, 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 percent of their coal requirements in 2014 and 2015.  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 2026.

• Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 57 percent of the requirements for 2022 through 2026.

• Current enrichment service contracts cover 100 percent of the requirements through 2024 and approximately 48 percent of the requirements for 2025 through 2026.

Fabrication services for Monticello and Prairie Island are 100 percent committed through 2027 and 2019, respectively. 

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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.

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, 2013 and 2012, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $389 million and $384 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2014 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, 2013, the NSP System was in compliance with mandated RPS, 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 22.9 percent and 22.4 percent of the NSP System’s total owned and purchased energy for 2013 and 2012, respectively.  Wind energy comprised 12.6 percent and 11.9 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively.  Hydroelectric energy comprised 7.4 percent and 7.0 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively.  Biomass and solar power comprised approximately 3.0 percent and 3.5 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, 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.  In 2013, the number of customers increased to approximately 37,000 from 24,000 in 2012. Windsource MWh sales declined slightly due to the loss of a large commercial participant from approximately 184,000 MWh in 2012 to 181,000 MWh in 2013. 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 679 PV systems with approximately 7.3 MW of aggregate capacity and over 561 PV systems with approximately 6.3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2013 and 2012, respectively.

Wind—The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota. The NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW.  In October 2013, the MPUC approved four new projects, which are anticipated to provide up to 750 MW of capacity, including two projects totaling 350 MW that will be owned by NSP-Minnesota.   Two of the projects, the Pleasant Valley wind farm in Minnesota and the Border Winds wind farm in North Dakota are expected to be operational by 2015. 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 for 2013 and 2012.  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 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 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 approximately 1,870 MW of wind energy on its system at the end of 2013 and 2012. With the new projects, the NSP System is anticipated to have approximately 2,600 MW of wind power.

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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 2013, 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.

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, asset transactions and mergers, 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 in July 2011 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively.  In Order 1000, the FERC required utilities, including RTO’s such as MISO, to file compliance tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region.  In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation.  A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area. Various parties have appealed Order 1000 final rules to the D.C. Circuit. NSP-Wisconsin is participating in the appeals in coordination with other MISO transmission owners and utilities who oppose certain aspects of the rules, including the ROFR prohibition. Briefs have been filed by parties challenging the final rules, and by the FERC and by parties supporting the final rules. Oral arguments are scheduled for March 20, 2014. The date for a Court ruling is uncertain.

The removal of a federal ROFR would eliminate rights that NSP-Wisconsin currently has under the MISO tariff to build certain transmission projects within its footprint.  The FERC required that the opportunity to build such projects would extend to competitive transmission developers.  Compliance with Order 1000 for NSP-Wisconsin will occur through changes to the MISO tariff.  MISO made its initial compliance filings to incorporate new provisions into its tariff regarding regional planning and cost allocation. The FERC has ruled on the initial regional compliance filings for MISO, and directed further changes to fully address the requirements of Order 1000. An additional regional compliance filing has been submitted by MISO, and FERC action on the supplemental compliance filing is pending. Several parties, including Xcel Energy, also sought rehearing of the FERC orders requiring changes to the initial MISO compliance filing. The rehearing requests are also pending FERC action.

Filings to address Order 1000 interregional planning and cost allocation requirements with other regions were made in July 2013.

NSP-System

In 2012, Minnesota enacted legislation that preserves ROFR rights for Minnesota utilities at the state level.  This legislation is similar to legislation previously passed in North Dakota and South Dakota.  Wisconsin has not developed such legislation.  The FERC’s initial order to address the regional requirements of Order 1000 required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. NSP-Minnesota, NSP-Wisconsin and other MISO transmission owners requested rehearing of this issue. The rehearing request is pending the FERC’s action. The FERC has accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability.

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 ruled favorably on 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 (also known as the Badger Coulee line) belong equally to NSP-Wisconsin and American Transmission Company, LLC (ATC).  In August 2012, 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. A joint CPCN application was filed with the PSCW in October 2013.

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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, Wis. to Madison, Wis. transmission line complaint filed by Xcel Energy Services Inc. and NSP-Wisconsin against ATC, that the FERC should determine that MISO should have designated the Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. CapX2020 line and the La Crosse, Wis. to Madison, Wis. line as a single facility under the MISO Transmission Owners Agreement and Tariff.  Thus, ATC should have been designated as the owner of the La Crosse, Wis. to Madison, Wis. 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, Minn. to La Crosse, Wis. and the La Crosse, Wis. to Madison, Wis. lines are separate.  ATC did not seek rehearing and therefore the FERC order is final and MISO’s prior ownership decisions stand, which brings this matter to a close.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature.  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 serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving.  Certain parties appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit).  In June 2013, the Seventh Circuit upheld the FERC MVP tariff orders allocating MVP project costs regionally, but remanded the FERC decision to not apply the regional charge to transmission service transactions crossing into the PJM RTO. U.S. Supreme Court review of the Seventh Circuit decision has been requested and the response is pending. 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, designed to ensure that any generator scheduled or dispatched by MISO receives 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. The FERC has allowed allocating a greater portion of the RSG costs related to resources committed for voltage and local reliability requirements to the market participants serving the loads that benefit from such commitments. Certain of the FERC’s orders remain pending on rehearing. An appeal to the D.C. Circuit has been held in abeyance, pending the FERC’s disposition of rehearing requests. If FERC were to reverse or modify the prior orders on rehearing, the NSP system could be subject to additional RSG charges for prior periods. NSP-Wisconsin recovers RSG costs in its fuel and purchased energy recovery mechanism in Wisconsin and through its power supply cost recovery mechanism in Michigan.

MISO ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against all FERC jurisdictional MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for RTO membership and being an independent transmission company), effective Nov. 12, 2013. In January 2014, Xcel Energy Services, Inc filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO Transmission Owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO Transmission Owners’ motion to dismiss. The complaint is pending FERC action. The estimated impact of FERC granting the complaint could amount to a reduction of revenue of $11.7 million annually for NSP-Minnesota and NSP-Wisconsin. NSP-Minnesota and NSP-Wisconsin would seek to offset any reduction in wholesale revenues through increases in retail rates.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2013			2012			2011
Electric sales (Millions of KWh)
Residential	1,990			1,921			1,982
Large commercial and industrial	1,698			1,739			1,678
Small commercial and industrial	2,837			2,763			2,718
Public authorities and other	36			35			33
Total retail	6,561			6,458			6,411
Sales for resale	1			412			546
Total energy sold	6,562			6,870			6,957
Number of customers at end of period
Residential	213,665			211,727			211,369
Large commercial and industrial	107			108			103
Small commercial and industrial	38,549			38,359			37,933
Public authorities and other	1,149			1,153			1,156
Total retail	253,470			251,347			250,561
Wholesale	—			9			10
Total customers	253,470			251,356			250,571
Electric revenues (Thousands of Dollars)
Residential	$	247,081		$	223,191		$	226,159
Large commercial and industrial	125,151			120,694			116,715
Small commercial and industrial	267,796			247,003			240,168
Public authorities and other	6,184			5,762			5,657
Total retail	646,212			596,650			588,699
Wholesale	2,524			31,583			37,884
Interchange revenues from NSP-Minnesota	136,917			125,344			124,334
Other electric revenues	3,515			3,988			4,219
Total electric revenues	$	789,168		$	757,565		$	755,136
KWh sales per retail customer	25,885			25,694			25,587
Revenue per retail customer	$	2,549		$	2,374		$	2,350
Residential revenue per KWh		12.42	¢		11.62	¢		11.41	¢
Large commercial and industrial revenue per KWh	7.37			6.94			6.96
Small commercial and industrial revenue per KWh	9.44			8.94			8.84
Total retail revenue per KWh	9.85			9.24			9.18
Wholesale revenue per KWh (a)	n/a			7.67			6.94

^(a)  As of Jan. 1, 2013, NSP-Wisconsin no longer served any wholesale municipal electric customers.  Rates for wholesale municipal services provided in 2012 were subject to a final true-up, which was completed in 2013.

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Energy Source Statistics

	Year Ended Dec. 31
	2013			2012			2011
NSP System	Millions ofKWh	Percent of Generation		Millions ofKWh	Percent of Generation		Millions ofKWh	Percent of Generation
Coal	15,844	36	%	16,023	35	%	20,131	44	%
Nuclear	12,161	28		13,231	29		13,332	29
Natural Gas	5,550	13		6,200	13		3,016	7
Wind (a)	5,481	13		5,443	12		4,312	9
Hydroelectric	3,223	7		3,193	7		3,444	8
Other (b)	1,323	3		1,617	4		1,453	3
Total	43,582	100	%	45,707	100	%	45,688	100	%
Owned generation	29,249	67	%	31,365	69	%	31,668	69	%
Purchased generation	14,333	33		14,342	31		14,020	31
Total	43,582	100	%	45,707	100	%	45,688	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, and was approximately 0.008, 0.006, and 0.003 net million KWh for 2013, 2012, and 2011, respectively.

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 customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 2000 to 2013, average annual sales to the typical NSP-Wisconsin residential customer declined 16 percent and the typical small commercial and industrial customer increased 7 percent on a weather-normalized basis 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 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. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. 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 including: requiring use of automatic or remote-controlled shut-off valves; 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 $2 million per day for related violations. While NSP-Wisconsin cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it 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 155,087 MMBtu, which occurred on Jan. 21, 2013, and 143,134 MMBtu, which occurred on Jan. 19, 2012.

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 132,591 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 2013-2014 supply plan was approved by the PSCW in November 2013.

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:

2013	$	4.51
2012	4.36
2011	5.18

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 2014 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, 2013, NSP-Wisconsin was committed to approximately $82 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 13 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
	2013		2012		2011
Natural gas deliveries (Thousands of MMBtu)
Residential	7,505		5,737		6,571
Commercial and industrial	10,131		8,197		8,476
Total retail	17,636		13,934		15,047
Transportation and other	4,344		4,177		3,983
Total deliveries	21,980		18,111		19,030
Number of customers at end of period
Residential	96,974		95,715		94,430
Commercial and industrial	12,646		12,506		12,392
Total retail	109,620		108,221		106,822
Transportation and other	23		22		22
Total customers	109,643		108,243		106,844
Natural gas revenues (Thousands of Dollars)
Residential	$	67,745	$	51,302	$	60,772
Commercial and industrial	63,896		47,771		57,077
Total retail	131,641		99,073		117,849
Transportation and other	1,226		4,027		1,598
Total natural gas revenues	$	132,867	$	103,100	$	119,447
MMBtu sales per retail customer	160.88		128.76		140.86
Revenue per retail customer	$	1,201	$	915	$	1,103
Residential revenue per MMBtu	9.03		8.94		9.25
Commercial and industrial revenue per MMBtu	6.31		5.83		6.73
Transportation and other revenue per MMBtu	0.28		0.96		0.40

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 for further discussion.

Competition

NSP-Wisconsin remains a vertically integrated utility subject to traditional cost-of-service regulation. Within this construct, however, NSP-Wisconsin is subject to different public policies that promote competition and the development of energy markets. 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. Customers also have the opportunity to supply their own power with on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

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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. In addition, FERC Order 1000 seeks to establish competition for construction and operation of new electric transmission facilities. NSP-Wisconsin has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. While facing these challenges, NSP-Wisconsin’s believes its rates and services are competitive with currently available alternatives. NSP-Wisconsin continues to evaluate policies, products and strategies to enable it to compete in the changing energy marketplace. As of Jan. 1, 2013 all of NSP-Wisconsin’s wholesale customers began purchasing power from an alternate supplier.

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 11 to 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, 2013, NSP-Wisconsin had 568 full-time employees and four part-time employees, of which 399 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 the Board of Directors oversees and holds management accountable.  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, including tone at the top, which mitigates risk.  Building on this culture of compliance, we manage and further 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 communicates regularly with Xcel Energy Inc.’s Board and key stakeholders regarding risk.  Senior management presents a periodic assessment of key risks to the Board.  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. Management also provides information to the Board in presentations and communications over the course of the year.

The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees. Each Board committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. Xcel Energy Inc.’s Board of Directors has overall responsibility for risk oversight and with the committees periodically undertakes the review of the charters to ensure that oversight of key risks are appropriately considered by the various Board committees. Xcel Energy Inc.’s Board also reviews risks at an enterprise level and annually conducts a full day strategy session where it considers risks and confirms that Xcel Energy’s and NSP-Wisconsin's strategy appropriately addresses risk management and mitigation and reviews the performance and annual goals of each business area.

As described above, the Board reviews senior management’s key risk assessment that analyzes the most likely areas of future risk to Xcel Energy. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

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Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements 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, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards.  Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. 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, 2013, 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.

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 and other GHGs, 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.

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

Financial Risks

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

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

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.  We 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 has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.  Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.  Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, adverse regulatory rulings 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.  Capital market disruption events and resulting broad financial market distress, 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.

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We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection 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 have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the 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. We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

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 Southwest Power Pool, Inc., 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 with modifications to these funding requirements 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.

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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 as well as natural gas. As a result we 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 customers at previously authorized or anticipated costs.  Any such disruption, if significant, would 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, natural gas pipeline capacity, etc.

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

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

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

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 their 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, 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.

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

Our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed energy generation, 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. NSP-Wisconsin’s aging infrastructure may pose a risk to system reliability and expose us to premature financial obligations. NSP-Wisconsin is engaged in significant and ongoing infrastructure investment programs.

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 states 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 the level of potential damages resulting from these risks is greater.

Additionally, the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires additional verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

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, 2013, Xcel Energy Inc. and its utility subsidiaries had approximately $10.9 billion of long-term debt and $1.0 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.

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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, 2013, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19.4 million and $0.3 million of exposure. Xcel Energy also had additional guarantees of $32.1 million at Dec. 31, 2013 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.

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 2013, 2012 and 2011 we paid $31.0 million, $57.3 million and $32.9 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 most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of certain amounts if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level. See Item 5 for further discussion on dividend limitations.

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 may be subject to regulation under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and adopted new permitting requirements 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 proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built. If adopted, these regulations could significantly increase the cost of building new generating plants. By 2016, the EPA plans to develop and implement GHG regulations applicable to emissions from existing power plants. Such regulations could impose substantial costs on our system.

We have been, and in the future may be subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures 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 may be enacted.  The impact of legislation and regulations 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.

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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 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 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, NERC 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.

The FERC issued NOVs of its market manipulation rules to several market participants during 2013.  The potential penalties in one pending case exceed $400 million.  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 has lowered the correlation between sales and economic growth. Sales growth has been relatively flat due to lower level of economic activity, increased focus on energy efficiency and distributed generation. Instability in the financial markets 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.

Economic conditions may be impacted 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 decrease in revenues and additional costs to repair and insure our assets. These disruptions 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.  We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, 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.

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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 or other 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.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events 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 (e.g., information about our customers, employees, operations, infrastructure and assets) could be directly or indirectly affected by unintentional or deliberate cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States, and individuals. 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. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, 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 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.

We maintain security measures designed to protect our information technology systems, network infrastructure and other assets. However, these assets and 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.

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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.

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:
Station, Location and Unit	Fuel	Installed	Summer 2013 Net Dependable 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, 2013:

Conductor Miles
345 KV	1,152
161 KV	1,572
115 KV	1,739
Less than 115 KV	32,204

NSP-Wisconsin had 203 electric utility transmission and distribution substations at Dec. 31, 2013.

Natural gas utility mains at Dec. 31, 2013:

Miles
Distribution	2,295

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Item 3 — Legal Proceedings

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.

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 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 andIssuer 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. 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 during 2013 in excess of approximately $31.2 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements. NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 52.8 percent at Dec. 31, 2013 and $17.1 million in retained earnings was not restricted.

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

The dividends declared during 2013 and 2012 were as follows:

(Thousands of Dollars)	2013		2012
First quarter	$	7,519	$	8,119
Second quarter	7,757		8,080
Third quarter	8,037		33,005
Fourth quarter	8,032		7,667

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 Discussionand 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).

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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 NSP-Wisconsin’s Form 10-K and Exhibit 99.01 hereto.

Results of Operations

NSP-Wisconsin’s net income was $59.5 million for 2013 compared with $50.0 million for 2012.  Higher earnings from electric and natural gas rates and cooler winter weather were partially offset by higher O&M expenses and depreciation.

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)	2013			2012
Electric revenues	$	789		$	758
Electric fuel and purchased power	(434		)	(425		)
Electric margin	$	355		$	333

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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)	2013 vs. 2012
Retail rate increase (Wisconsin)	$	34
Interchange Agreement billings with NSP-Minnesota	17
Fuel and purchased power cost recovery	8
Estimated impact of weather	5
Firm wholesale	(32		)
Conservation program incentives	(2		)
Other, net	1
Total increase in electric revenues	$	31

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increase (Wisconsin)	$	34
Interchange Agreement billings with NSP-Minnesota	10
Estimated impact of weather	5
Firm wholesale	(20		)
Timing of fuel recovery	(9		)
Other, net	2
Total increase in electric margin	$	22

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)	2013			2012
Natural gas revenues	$	133		$	103
Cost of natural gas sold and transported	(82		)	(61		)
Natural gas margin	$	51		$	42

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)	2013 vs. 2012
Purchased natural gas adjustment clause recovery	$	19
Estimated impact of weather	6
Retail rate increase (Wisconsin)	3
Retail sales growth	1
Other, net	1
Total increase in natural gas revenues	$	30

29

Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	6
Retail rate increase (Wisconsin)	3
Retail sales growth	1
Other, net	(1		)
Total increase in natural gas margin	$	9

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $8.0 million, or 4.8 percent, for 2013 compared with 2012.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2013 vs. 2012
Employee benefits	$	3
Electric and gas distribution costs	3
Plant generation costs	2
Transmission expense	1
Other, net	(1		)
Total increase in O&M expenses	$	8

Depreciation and Amortization — Depreciation and amortization increased $7.7 million, or 11.1 percent, for 2013 compared with 2012. The increases are primarily attributable to normal system expansion.

AFUDC, Equity and Debt— AFUDC increased $2.3 million for 2013 compared with 2012. The increase is primarily due to the expansion of transmission facilities.

Interest Charges — Interest charges increased $3.0 million, or 12.1 percent, for 2013 compared with 2012. The increase is primarily due to higher debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $6.9 million for 2013 compared with 2012.  The increase in income tax expense was primarily due to higher pretax earnings in 2013. The ETR was 38.0 percent for 2013, compared with 37.2 percent for 2012.

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.

30

Commodity Price Risk — NSP-Wisconsin is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for natural gas used in 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, 2013 and 2012, a 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact pretax interest expense annually by approximately $0.7 million and $0.4 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, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $0.6 million, while a decrease in prices of 10 percent would have an immaterial impact on credit exposure. At Dec. 31, 2012, 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 16 to the consolidated financial statements for summarized quarterly financial data.

31

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, 2013. 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 (1992). Based on our assessment, we believe that, as of Dec. 31, 2013, NSP-Wisconsin’s internal control over financial reporting is effective at the reasonable assurance level 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. 24, 2014	Feb. 24, 2014

32

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 statements of capitalization of Northern States Power Company, a Wisconsin corporation, and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows, and common stockholder’s equity for each of the three years in the period ended December 31, 2013.  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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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 24, 2014

33

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2013			2012			2011
Operating revenues
Electric	$	789,168		$	757,565		$	755,136
Natural gas	132,867			103,100			119,447
Other	1,003			1,177			1,207
Total operating revenues	923,038			861,842			875,790
Operating expenses
Electric fuel and purchased power, non-affiliates	18,129			19,440			20,957
Purchased power, affiliates	416,173			405,016			399,649
Cost of natural gas sold and transported	81,572			61,370			78,208
Operating and maintenance expenses	175,522			167,503			164,323
Conservation program expenses	12,333			14,442			12,883
Depreciation and amortization	76,897			69,234			68,574
Taxes (other than income taxes)	25,231			24,971			23,688
Total operating expenses	805,857			761,976			768,282
Operating income	117,181			99,866			107,508
Other income, net	253			476			98
Allowance for funds used during construction — equity	4,259			2,104			1,007
Interest charges and financing costs
Interest charges — includes other financing costs of $1,538, $1,574 and $1,713, respectively	27,797			24,799			24,168
Allowance for funds used during construction — debt	(1,981		)	(1,862		)	(175		)
Total interest charges and financing costs	25,816			22,937			23,993
Income before income taxes	95,877			79,509			84,620
Income taxes	36,409			29,558			33,614
Net income	$	59,468		$	49,951		$	51,006

See Notes to Consolidated Financial Statements

34

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2013		2012		2011
Net income	$	59,468	$	49,951	$	51,006
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $51, $51 and $51, respectively.	76		77		76
Other comprehensive income	76		77		76
Comprehensive income	$	59,544	$	50,028	$	51,082

See Notes to Consolidated Financial Statements

35

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2013			2012			2011
Operating activities
Net income	$	59,468		$	49,951		$	51,006
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	78,048			70,372			69,900
Deferred income taxes	25,789			27,107			35,610
Amortization of investment tax credits	(664		)	(626		)	(611		)
Allowance for equity funds used during construction	(4,259		)	(2,104		)	(1,007		)
Provision for bad debts	3,988			3,329			3,842
Net derivative (gains) losses	(279		)	127			127
Changes in operating assets and liabilities:
Accounts receivable	(12,702		)	(15,953		)	(4,013		)
Accrued unbilled revenues	(2,496		)	(470		)	2,911
Inventories	(1,879		)	6,018			913
Other current assets	(3,749		)	(3,172		)	(1,180		)
Accounts payable	(1,811		)	5,828			(16,614		)
Net regulatory assets and liabilities	(2,062		)	3,623			10,008
Other current liabilities	7,589			3,681			(2,260		)
Pension and other employee benefit obligations	(8,759		)	(10,857		)	(7,214		)
Change in other noncurrent assets	232			14			564
Change in other noncurrent liabilities	1,119			(595		)	(2,682		)
Net cash provided by operating activities	137,573			136,273			139,300
Investing activities
Utility capital/construction expenditures	(201,278		)	(152,759		)	(140,982		)
Allowance for equity funds used during construction	4,259			2,104			1,007
Other, net	(421		)	916			(112		)
Net cash used in investing activities	(197,440		)	(149,739		)	(140,087		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	29,000			(27,000		)	66,000
Proceeds from notes payable to affiliates	—			50			111,300
Repayments of notes payable to affiliates	(80		)	—			(148,350		)
Proceeds from issuance of long-term debt	—			97,916			—
Repayments of long-term debt	(160		)	(97		)	(96		)
Capital contributions from parent	58,977			2,796			—
Dividends paid to parent	(30,980		)	(57,311		)	(32,941		)
Net cash provided by (used in) financing activities	56,757			16,354			(4,087		)
Net change in cash and cash equivalents	(3,110		)	2,888			(4,874		)
Cash and cash equivalents at beginning of period	4,459			1,571			6,445
Cash and cash equivalents at end of period	$	1,349		$	4,459		$	1,571
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(24,376	)	$	(21,035	)	$	(22,616	)
Cash (paid) received for income taxes, net	(9,842		)	(5,841		)	1,116
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	27,222		$	10,618		$	9,427

See Notes to Consolidated Financial Statements

36

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	1,349		$	4,459
Accounts receivable, net	59,269			50,706
Accrued unbilled revenues	51,634			49,138
Inventories	21,475			19,685
Regulatory assets	14,866			12,048
Prepaid taxes	27,518			24,688
Deferred income taxes	14,953			—
Prepayments and other	5,056			4,394
Total current assets	196,120			165,118
Property, plant and equipment, net	1,442,779			1,298,236
Other assets
Regulatory assets	233,193			240,459
Other investments	3,650			3,232
Other	3,651			4,040
Total other assets	240,494			247,731
Total assets	$	1,879,393		$	1,711,085
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	107		$	1,246
Short-term debt	68,000			39,000
Notes payable to affiliates	470			550
Accounts payable	52,086			30,723
Accounts payable to affiliates	24,986			31,556
Dividends payable to parent	8,032			7,667
Regulatory liabilities	9,717			6,086
Taxes accrued	5,638			839
Environmental liabilities	28,785			23,427
Accrued interest	7,507			7,304
Other	9,376			10,955
Total current liabilities	214,704			159,353
Deferred credits and other liabilities
Deferred income taxes	305,139			261,800
Deferred investment tax credits	9,698			8,911
Regulatory liabilities	126,424			123,746
Environmental liabilities	79,703			84,655
Customer advances	16,008			15,631
Pension and employee benefit obligations	45,708			63,643
Other	9,237			8,923
Total deferred credits and other liabilities	591,917			567,309
Commitments and contingencies
Capitalization
Long-term debt	468,490			467,317
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2013 and 2012, respectively	93,300			93,300
Additional paid in capital	248,844			189,867
Retained earnings	262,499			234,376
Accumulated other comprehensive loss	(361		)	(437		)
Total common stockholder’s equity	604,282			517,106
Total liabilities and equity	$	1,879,393		$	1,711,085

See Notes to Consolidated Financial Statements

37

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in thousands, except share data)

	Common Stock								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2010	933,000	$	93,300	$	187,071	$	222,897		$	(590	)	$	502,678
Net income						51,006						51,006
Other comprehensive income									76			76
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
Net income						49,951						49,951
Other comprehensive income									77			77
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
Net income						59,468						59,468
Other comprehensive income									76			76
Common dividends declared to parent						(31,345		)				(31,345		)
Contribution of capital by parent				58,977								58,977
Balance at Dec. 31, 2013	933,000	93,300		248,844		262,499			$	(361	)	$	604,282

See Notes to Consolidated Financial Statements

38

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2013			2012
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			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%	558			591
Other	1,760			1,829
Unamortized discount	(2,321		)	(2,457		)
Total	468,597			468,563
Less current maturities	107			1,246
Total long-term debt	$	468,490		$	467,317
Common Stockholder’s Equity
Common stock  — 1,000,000 shares authorized of $100 par value;
933,000 shares outstanding at Dec. 31, 2013 and 2012, respectively	$	93,300		$	93,300
Additional paid in capital	248,844			189,867
Retained earnings	262,499			234,376
Accumulated other comprehensive loss	(361		)	(437		)
Total common stockholder’s equity	$	604,282		$	517,106

^(a)  Resource recovery financing

See Notes to Consolidated Financial Statements

39

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.

40

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.

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 required to be decommissioned early by a regulator 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, 3.5 and 3.6 percent for the years ended Dec. 31, 2013, 2012 and 2011, 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 financing 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.

AROs — 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 effective 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.

41

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.

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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.

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.

RECs — 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. 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 remediation 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.

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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.

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, 2013 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

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 No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Wisconsin implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 9 for the required disclosures.

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 regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  NSP-Wisconsin implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 13 for the required disclosures.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Accounts receivable, net (a)
Accounts receivable	$	64,180		$	55,039
Less allowance for bad debts	(4,911		)	(4,333		)
	$	59,269		$	50,706

^(a)  Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	6,437	$	6,172
Fuel	5,915		6,664
Natural gas	9,123		6,849
	$	21,475	$	19,685

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(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	1,913,354		$	1,795,239
Natural gas plant	236,047			224,625
Common and other property	112,886			111,319
CWIP	127,954			62,629
Total property, plant and equipment	2,390,241			2,193,812
Less accumulated depreciation	(947,462		)	(895,576		)
	$	1,442,779		$	1,298,236

4. Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2013
Borrowing limit	$	150
Amount outstanding at period end	68
Average amount outstanding	41
Maximum amount outstanding	71
Weighted average interest rate, computed on a daily basis	0.30		%
Weighted average interest rate at period end	0.27

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	68			39			66
Average amount outstanding	20			61			24
Maximum amount outstanding	71			116			70
Weighted average interest rate, computed on a daily basis	0.31		%	0.39		%	0.37		%
Weighted average interest rate at period end	0.27			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, 2013 and 2012, 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.

NSP-Wisconsin has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $150 million and the credit facility terminates in July 2017.

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

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

• The credit facility has a financial covenant requiring that the 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 47 percent at Dec. 31, 2013. 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.

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• 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.

• The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.

• The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

At Dec. 31, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	68.0	$	82.0

^(a)  Credit facility expires in July 2017.

^(b)  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, 2013 and 2012.

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, 2013			Dec. 31, 2012
Notes payable to affiliates	$	0.5		$	0.6
Weighted average interest rate	0.24		%	0.33		%

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. 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 $100.0 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 $150.0 million due in 2018.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $3.5 million and $3.6 million, net of amortization, at Dec. 31, 2013 and 2012, respectively.  NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

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 $31.2 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements.  NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 52.8 percent at Dec. 31, 2013 and $17.1 million in retained earnings was not restricted.

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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, 2013:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	13,337	$	4,659	$	30,199	77.9	%
La Crosse, Wis. to Madison, Wis.	—		—		5,431		50.0
Total NSP-Wisconsin	$	13,337	$	4,659	$	35,630

NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.

6. Income Taxes

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 June 2015.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution are uncertain.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2013, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011. As of Dec. 31, 2013, no material adjustments had been proposed for these years.  There are currently no other state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.4		1.2
Total unrecognized tax benefit	$	1.5	$	1.3

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

(Millions of Dollars)	2013			2012			2011
Balance at Jan. 1	$	1.3		$	1.5		$	1.9
Additions based on tax positions related to the current year	0.7			0.5			0.6
Reductions based on tax positions related to the current year	—			(0.2		)	(0.1		)
Additions for tax positions of prior years	0.5			0.3			0.7
Reductions for tax positions of prior years	—			(0.8		)	(0.3		)
Settlements with taxing authorities	(1.0		)	—			(1.2		)
Lapse of applicable statutes of limitations	—			—			(0.1		)
Balance at Dec. 31	$	1.5		$	1.3		$	1.5

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

(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(0.4	)	$	(0.9	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As NSP-Wisconsin had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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)	2013	2012
Federal NOL carryforward	46.8	44.3
Federal tax credit carryforwards	4.4	8.0
State NOL carryforward	6.3	3.4

The federal carryforward periods expire between 2021 and 2033.  The state carryforward periods expire between 2022 and 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:

	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	5.0		3.4		4.4
Tax credits recognized	(0.9	)	(0.9	)	(0.9	)
Regulatory differences — utility plant items	(0.9	)	(0.3	)	0.5
Change in unrecognized tax benefits	—		0.1		(0.2	)
Other, net	(0.2	)	(0.1	)	0.9
Effective income tax rate	38.0	%	37.2	%	39.7	%

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

(Thousands of Dollars)	2013			2012			2011
Current federal tax expense (benefit)	$	5,902		$	930		$	(1,540	)
Current state tax expense	4,628			2,216			1,573
Current change in unrecognized tax expense (benefit)	754			(69		)	(1,418		)
Deferred federal tax expense	23,794			25,089			30,251
Deferred state tax expense	2,720			1,890			4,105
Deferred change in unrecognized tax (benefit) expense	(725		)	128			1,254
Deferred investment tax credits	(664		)	(626		)	(611		)
Total income tax expense	$	36,409		$	29,558		$	33,614

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

(Thousands of Dollars)	2013			2012			2011
Deferred tax expense excluding items below	$	27,516		$	27,995		$	34,017
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,676		)	(837		)	1,644
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	25,789		$	27,107		$	35,610

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

(Thousands of Dollars)	2013		2012
Deferred tax liabilities:
Difference between book and tax bases of property	$	287,121	$	265,202
Regulatory assets	57,296		52,898
Employee benefits	16,953		16,862
Other	10,193		10,535
Total deferred tax liabilities	$	371,563	$	345,497
Deferred tax assets:
Environmental remediation	43,501		43,344
NOL carryforward	17,384		17,588
Regulatory liabilities	6,205		5,927
Deferred investment tax credits	5,976		5,766
Tax credit carryforward	4,440		8,011
Other	3,871		2,191
Total deferred tax assets	$	81,377	$	82,827
Net deferred tax liability	$	290,186	$	262,670

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, 2013, NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016.

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.

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.

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.

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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.

Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

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, 2013 and 2012 were $36.5 million and $39.4 million, respectively, of which $0.6 million and $0.6 million, respectively, was attributable to NSP-Wisconsin. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 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 2013 were below the assumed level of 7.25 percent. Investment returns in 2012 were above the assumed level of 7.50 percent while returns in 2011 were below the assumed level of 8.00 percent. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions. In 2014, 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.

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

	2013		2012
Domestic and international equity securities	31	%	29	%
Long-duration fixed income and interest rate swap securities	29		30
Short-to-intermediate term fixed income securities	16		12
Alternative investments	22		27
Cash	2		2
Total	100	%	100	%

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, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	4,332	$	—	$	—	$	4,332
Derivatives	—		937		—		937
Government securities	—		6,711		—		6,711
Corporate bonds	—		24,955		—		24,955
Asset-backed securities	—		307		—		307
Mortgage-backed securities	—		684		—		684
Common stock	4,533		—		—		4,533
Private equity investments	—		—		7,502		7,502
Commingled funds	—		84,364		—		84,364
Real estate	—		—		2,299		2,299
Securities lending collateral obligation and other	—		311		—		311
Total	$	8,865	$	118,269	$	9,801	$	136,935

	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

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The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	749	$	—		$	—		$	—		$	(749	)	$	—
Mortgage-backed securities	2,128		—			—			—			(2,128		)	—
Private equity investments	8,545		1,083			(1,960		)	(166		)	—			7,502
Real estate	3,472		(129		)	247			450			(1,741		)	2,299
Total	$	14,894	$	954		$	(1,713	)	$	284		$	(4,618	)	$	9,801

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		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

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		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

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)	2013			2012
Accumulated Benefit Obligation at Dec. 31	$	153,894		$	169,939
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	179,995		$	159,766
Service cost	5,682			4,568
Interest cost	6,924			7,765
Plan amendments	(1,109		)	216
Actuarial (gain) loss	(11,097		)	21,083
Benefit payments	(16,465		)	(13,403		)
Obligation at Dec. 31	$	163,930		$	179,995

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	136,546		$	121,348
Actual return on plan assets	5,525			16,079
Employer contributions	11,329			12,522
Benefit payments	(16,465		)	(13,403		)
Fair value of plan assets at Dec. 31	$	136,935		$	136,546

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(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(26,995	)	$	(43,449	)

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

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	84,773	$	99,338
Prior service cost	778		2,290
Total	$	85,551	$	101,628

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	7,631	$	6,895
Noncurrent regulatory assets	77,920		94,733
Total	$	85,551	$	101,628

Measurement date Dec. 31, 2013 Dec. 31, 2012

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75
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, 2012 and 2013 to meet minimum funding requirements.

The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014:

• In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $8.0 million was attributable to NSP-Wisconsin;

• In 2013, contributions of $192.4 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 2013 resulting in a decrease of the projected benefit obligation due to fully insuring the long-term disability benefit for NSP bargaining participants. This decrease was partially offset by an increase to the projected benefit obligation resulting from a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan. In 2012, the plan was amended 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.

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	5,682		$	4,568		$	4,271
Interest cost	6,924			7,765			8,031
Expected return on plan assets	(9,995		)	(10,489		)	(11,484		)
Amortization of prior service cost	417			1,771			1,895
Amortization of net loss	7,924			6,004			4,070
Net periodic pension cost	$	10,952		$	9,619		$	6,783

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.00	%	5.00	%	5.50	%
Expected average long-term increase in compensation level	3.75		4.00		4.00
Expected average long-term rate of return on assets	7.25		7.50		8.00

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 $2.2 million, $1.8 million and $1.3 million in 2013, 2012 and 2011, 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 2014 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 expense to these plans for NSP-Wisconsin was approximately $1.3 million in 2013, $1.2 million in 2012 and $1.1 million in 2011.

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 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.

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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, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	31	$	—		$	—	$	31
Derivatives	—		(2		)	—		(2		)
Government securities	—		89			—		89
Insurance contracts	—		80			—		80
Corporate bonds	—		79			—		79
Asset-backed securities	—		5			—		5
Mortgage-backed securities	—		37			—		37
Commingled funds	—		452			—		452
Other	—		(25		)	—		(25		)
Total	$	31	$	715		$	—	$	746

	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

The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	1	$	—	$	—	$	—	$	(1	)	$	—
Mortgage-backed securities	54		—		—		—		(54		)	—
Total	$	55	$	—	$	—	$	—	$	(55	)	$	—

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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

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

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)	2013			2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	19,432		$	22,127
Service cost	25			20
Interest cost	760			1,075
Medicare subsidy reimbursements	31			189
Plan amendments	—			(3,440		)
Plan participants’ contributions	621			893
Actuarial (gain) loss	(1,724		)	1,486
Benefit payments	(1,992		)	(2,918		)
Obligation at Dec. 31	$	17,153		$	19,432

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	647		$	746
Actual return on plan assets	(13		)	3
Plan participants’ contributions	621			893
Employer contributions	1,483			1,923
Benefit payments	(1,992		)	(2,918		)
Fair value of plan assets at Dec. 31	$	746		$	647

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status	$	(16,407	)	$	(18,785	)
Current liabilities	(718		)	(943		)
Noncurrent liabilities	(15,689		)	(17,842		)
Net postretirement amounts recognized on consolidated balance sheets	$	(16,407	)	$	(18,785	)

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	11,098		$	13,730
Prior service credit	(3,187		)	(3,538		)
Transition obligation	—			1
Total	$	7,911		$	10,193

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	570	$	433
Noncurrent regulatory assets	7,341		9,760
Total	$	7,911	$	10,193

Measurement date Dec. 31, 2013 Dec. 31, 2012

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	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.82	%	4.10	%
Mortality table	RP 2000		RP 2000
Health care costs trend rate — initial	7.00	%	7.50	%

Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five 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 one-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	$	1,773	$	(1,486	)
Service and interest components	78		(61		)

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 $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $1.5 million, $1.9 million and $2.4 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which $1.5 million is attributable to NSP-Wisconsin.

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)	2013			2012			2011
Service cost	$	25		$	20		$	17
Interest cost	760			1,075			1,144
Expected return on plan assets	(42		)	(50		)	(74		)
Amortization of transition obligation	1			171			171
Amortization of prior service credit	(351		)	(14		)	(14		)
Amortization of net loss	963			486			366
Net periodic postretirement benefit cost	$	1,356		$	1,688		$	1,610

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.10	%	5.00	%	5.50	%
Expected average long-term rate of return on assets	7.11		6.75		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.

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Projected Benefit Payments

The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	ProjectedPension BenefitPayments		Gross Projected Postretirement Health Care BenefitPayments		ExpectedMedicare Part DSubsidies		Net Projected Postretirement Health Care BenefitPayments
2014	$	21,677	$	1,491	$	27	$	1,464
2015	14,257		1,459		25		1,434
2016	13,420		1,444		24		1,420
2017	13,851		1,384		20		1,364
2018	12,983		1,357		18		1,339
2019-2023	64,935		6,229		82		6,147

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, 2013, 2012 and 2011.  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)	2013		2012		2011
Multiemployer plan contributions:
Pension	$	130	$	163	$	169
Total	$	130	$	163	$	169

8. Other Income, Net

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

(Thousands of Dollars)	2013			2012			2011
Interest income	$	538		$	736		$	324
Other nonoperating income	152			129			67
Insurance policy expense	(427		)	(389		)	(283		)
Other nonoperating expense	(10		)	—			(10		)
Other income, net	$	253		$	476		$	98

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.

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

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

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, for trading purposes and 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, 2013, 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 interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale.

The following table details the gross notional amounts of commodity options at Dec. 31, 2013 and 2012:

(Amounts in Thousands)(a)(b)	Dec. 31, 2013	Dec. 31, 2012
MMBtu of natural gas	987	53

^(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 derivatives 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.

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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)	2013			2012			2011
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(437	)	$	(514	)	$	(590	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			77			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(361	)	$	(437	)	$	(514	)

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, 2013, 2012 and 2011.

During the year ended Dec. 31, 2013, 2012 and 2011, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million, $0.4 million and $3.6 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 and option premium amortization totaling $0.7 million, $2.9 million and $2.9 million were recognized for each of the years ended Dec. 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	580	$	—	$	580	$	—	$	580

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

^(a)  NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013 and 2012.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.

^(c)  Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2013				2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,597	$	518,269	$	468,563	$	576,353

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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, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

10. Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

Wisconsin 2014 Electric and Gas Rate Case—In May 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent. The electric rate increase included a $4.5 million adjustment related to proceeds from a nuclear settlement agreement with the DOE.

The rate filing was based on a 2014 forecast test year, an ROE of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.

In October 2013, NSP-Wisconsin filed rebuttal testimony revising the requested electric rate increase to $34.3 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments.

In December 2013, the PSCW approved an electric rate increase of approximately $19.5 million or 3.1 percent based on a 10.2 percent ROE and an equity ratio of 52.5 percent. The PSCW also approved cost deferrals of $4.1 million for interchange agreement amounts from NSP-Minnesota related to the Monticello EPU project until the MPUC completes its prudence review. The PSCW did not change rates for NSP-Wisconsin’s natural gas utility. New electric rates went into effect on Jan. 1, 2014.

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.

CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including the NSP System that has proposed several groups of transmission projects to be completed 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 entered into various long-term commitments 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 2014 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 for future rate recovery or refund when fuel costs differ from the amount included in rates by more than two percent on an annual basis, as determined by the PSCW after an opportunity for a hearing and an earnings test based on NSP-Wisconsin’s authorized ROE.

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The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2013 are as follows:

(Millions of dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	6.2	$	13.4	$	11.9
2015	1.3		0.3		11.6
2016	0.7		0.3		11.7
2017	0.7		0.2		9.5
2018	0.7		—		4.4
Thereafter	4.1		—		18.9
Total (a)	$	13.7	$	14.2	$	68.0

^(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.

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 $1.4 million, $1.1 million and $1.4 million for 2013, 2012 and 2011, respectively.

Future commitments under operating leases are:

(Millions of Dollars)
2014	$	0.8
2015	0.8
2016	0.8
2017	0.9
2018	0.9
Thereafter	8.8
Total	$	13.0

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, 2013		Dec. 31, 2012
Current assets	$	223	$	357
Property, plant and equipment, net	2,427		2,599
Other noncurrent assets	112		105
Total assets	$	2,762	$	3,061
Current liabilities	$	233	$	1,388
Mortgages and other long-term debt payable	1,687		617
Other noncurrent liabilities	42		39
Total liabilities	$	1,962	$	2,044

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 $13.6 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 $13.2 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 $127.3 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 $19 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 September 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites.  NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units.  Premiums are expensed over the policy term.  All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds.  Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.  However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $40.2 million for property damage insurance if losses exceed accumulated reserve funds.

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	$	0.3	2017	(a)

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

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Environmental Contingencies

NSP-Wisconsin has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Wisconsin is pursuing, or intends to pursue, recovery from other PRPs and through the 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/Northern States Power Lakefront Superfund Site (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. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.

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 settlement negotiations with NSP-Wisconsin, 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 has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy 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. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. NSP-Wisconsin is in the process of negotiating a final pilot study work plan for possible implementation in late summer or early fall of 2014.

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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 is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At Dec. 31, 2013 and 2012, NSP-Wisconsin had recorded a liability of $104.6 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $25.2 million and $20.1 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.

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 historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and 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 three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 clean-up costs for the Phase I Project Area. The PSCW determined the timing of the clean-up of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the clean-up in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the clean-up by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

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 two 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 $3.9 million and $2.5 million for both of these sites at Dec. 31, 2013 and 2012, 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.

Environmental Requirements

Water and waste

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.

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Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Federal 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. A final rule is anticipated in April 2014. 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 entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Air

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. 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. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. 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 Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO₂ emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, 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 the re-proposed NSPS until its final requirements are known.

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.

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In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.

As 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 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At Dec. 31, 2013, 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 will not have any units subject to EGU MATS because it will cease coal combustion in Bay Front Unit 5.

Industrial Boiler (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 anticipated to be $17.2 million in total and is 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.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, other and hydro), electric distribution and transmission, natural gas transmission and distribution, and general property.  The electric production obligations include ash-containment facilities, storage tanks, control panels and 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.  The common general AROs include small obligations related to storage tanks and office buildings. These 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.

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A reconciliation of NSP-Wisconsin’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013 (a)
Electric plant
Steam production asbestos	$	1,962	$	—	$	43	$	—		$	2,005
Steam and other production ash containment	125		—		12		224			361
Electric distribution	13		—		1		22			36
Other	826		—		20		(557		)	289
Natural gas plant
Gas transmission and distribution	75		—		5		(5		)	75
Common and other property
Common miscellaneous	35		—		3		49			87
Total liability (b)	$	3,036	$	—	$	84	$	(267	)	$	2,853

(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Recognized		Accretion		Revisions to Prior Estimates		Ending Balance Dec. 31, 2012 (a)
Electric plant
Steam production asbestos	$	—	$	1,962	$	—	$	—	$	1,962
Steam and other production ash containment	120		—		5		—		125
Electric distribution	13		—		—		—		13
Other	186		—		7		633		826
Natural gas plant
Gas transmission and distribution	71		—		4		—		75
Common and other property
Common miscellaneous	34		—		1		—		35
Total liability (b)	$	424	$	1,962	$	17	$	633	$	3,036

^(a)  There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.

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

In 2013, NSP-Wisconsin revised ash containment facilities, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and common general AROs due to revised estimated cash flows. In 2012, 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, 2013 and 2012 were $116 million and $114 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.

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.

The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	4,376	$	117,684	$	2,521	$	109,162
Pension and retiree medical obligations (a)	7	Various	8,202		85,220		7,328		104,426
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		12,679		—		10,458
Losses on reacquired debt	4	Term of related debt	801		5,737		800		6,538
State commission adjustments	1	Plant lives	410		9,355		339		7,533
Conservation programs	1	Less than one year	404		—		691		—
Deferred income tax adjustment	1, 6	Typically plant lives	—		1,763		—		1,974
Recoverable purchased natural gas and electric energy costs		Less than one year	673		—		358		—
Other		Various	—		755		11		368
Total regulatory assets			$	14,866	$	233,193	$	12,048	$	240,459

^(a)  Includes the non-qualified pension plan.

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	116,293	$	—	$	113,949
DOE settlement	11	Less than one year	6,814		—		5,628		—
Investment tax credit deferrals	1, 6	Various	—		9,976		—		9,626
Conservation programs	1	Less than one year	1,187		—		73		—
Deferred electric production and natural gas costs	1	Less than one year	1,542		—		134		—
Other		Various	174		155		251		171
Total regulatory liabilities			$	9,717	$	126,424	$	6,086	$	123,746

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At Dec. 31, 2013 and 2012, approximately $0.1 million and $0.4 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes recoverable purchased natural gas and electric energy costs.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	76
Net current period OCI	76
Accumulated other comprehensive loss at Dec. 31	$	(361	)

Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Losses on cash flow hedges:
Interest rate derivatives	$	127		(a)
Total, pre-tax	127
Tax benefit	(51		)
Total amounts reclassified, net of tax	$	76

^(a)  Included in interest charges.

14. 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 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.

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 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.

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2013
Operating revenues (a)	$	789,168	$	132,867	$	1,003		$	—		$	923,038
Intersegment revenues	350		1,967		—			(2,317		)	—
Total revenues	$	789,518	$	134,834	$	1,003		$	(2,317	)	$	923,038
Depreciation and amortization	$	64,237	$	12,485	$	175		$	—		$	76,897
Interest charges and financing costs	22,966		2,749		101			—			25,816
Income tax expense (benefit)	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	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 costs	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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2011
Operating revenues (a)	$	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 costs	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

^(a)  Operating revenuesinclude $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

15. 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.

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.

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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)	2013		2012		2011
Operating revenues:
Electric	$	136,917	$	125,344	$	124,334
Operating expenses:
Purchased power	416,173		405,016		399,649
Transmission expense	42,460		44,942		40,870
Natural gas purchased for resale	97		116		98
Other operating expenses — paid to Xcel Energy Services Inc.	61,531		54,137		54,885
Interest expense	22		22		48

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

	2013				2012
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	18,584	$	—	$	26,632
PSCo	—		8		—		71
SPS	26		—		—		4
Other subsidiaries of Xcel Energy Inc.	1,569		6,394		586		4,849
	$	1,595	$	24,986	$	586	$	31,556

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	241,415	$	210,175	$	231,060	$	240,388
Operating income	37,401		22,466		40,769		16,545
Net income	19,685		10,544		22,013		7,225

	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

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

None.

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, 2013, 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.

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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, 2013 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 2014 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2013
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Consolidated Balance Sheets — As of Dec. 31, 2013 and 2012.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Consolidated Statements of Capitalization — As of Dec. 31, 2013 and 2012.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2013, 2012 and 2011.

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3.	Exhibits
*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
3.01*	Amended and restated articles of incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) Jan. 21, 2004).
3.02*	By-Laws of Northern States Power Co. (a Wisconsin corporation) as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03140)).
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 National Association, 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 National Association, 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 National Association, 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).

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).

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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).
10.15a*+	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).
10.15b*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Time-Based Restricted Stock Unit Agreement (Exhibit 10.14b to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2012).
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)).
10.20*+	First Amendment dated Feb. 20, 2013 to the Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.21*+	Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.22*+	First Amendment dated May 21, 2013 to the Xcel Energy Inc. Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.23*+	Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Non-Qualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.24*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
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.
101	The following materials from NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 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 Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) the Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, and (ix) Schedule II.

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SCHEDULE II

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2013, 2012 AND 2011

(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:
2013	$	4,333	$	3,988	$	1,199	$	4,609	$	4,911
2012	4,766		3,329		1,310		5,072		4,333
2011	4,262		3,842		1,241		4,579		4,766

^(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 (A WISCONSIN CORPORATION)
Feb. 24, 2014	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Senior Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)

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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EX-12.01

Exhibit 12.01

NSP-WISCONSIN AND SUBSIDIARIES

STATEMENT OF COMPUTATION OF

RATIO OF EARNINGS TO FIXED CHARGES

(amounts in thousands, except ratio)

	Year Ended Dec. 31
	2013		2012		2011		2010		2009
Earnings, as defined:
Pretax income	$	95,877	$	79,509	$	84,620	$	68,861	$	72,981
Add: Fixed charges	28,325		25,215		24,628		24,897		25,102
Total earnings, as defined	$	124,202	$	104,724	$	109,248	$	93,758	$	98,083
Fixed charges, as defined:
Interest charges	$	27,797	$	24,799	$	24,168	$	24,517	$	24,782
Interest component of leases	528		416		460		380		320
Total fixed charges, as defined	$	28,325	$	25,215	$	24,628	$	24,897	$	25,102
Ratio of earnings to fixed charges	4.4		4.2		4.4		3.8		3.9

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-192835 on Form S-3 of our report dated February 24, 2014, relating to the consolidated financial statements and financial statement schedule of Northern States Power Company, a Wisconsin corporation, and subsidiaries appearing in this Annual Report on Form 10-K of Northern States Power Company, a Wisconsin corporation, for the year ended December 31, 2013.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2014

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Mark E. Stoering, certify that:

1. I have reviewed this report on Form 10-K of Northern States Power Company (a Wisconsin corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 24, 2014

/s/ MARK E. STOERING

Mark E. Stoering

President, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-K of Northern States Power Company (a Wisconsin corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 24, 2014

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin) on Form 10-K for the year ended Dec. 31, 2013, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of NSP-Wisconsin certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Wisconsin as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 24, 2014

/s/ MARK E. STOERING

Mark E. Stoering

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NSP-Wisconsin and will be retained by NSP-Wisconsin and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

NSP-Wisconsin Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of NSP-Wisconsin, Xcel Energy Inc. or any of its other subsidiaries. These statements are based on management’s beliefs as well as assumptions and information currently available to management.  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.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause NSP-Wisconsin’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Wisconsin has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Wisconsin, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by NSP-Wisconsin, Xcel Energy Inc. and its other subsidiaries;

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of  compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementations of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in NSP-Wisconsin’s SEC filings, including “Risk Factors” in Item 1A of this Form 10-K for the year ended Dec. 31, 2013, or in other publicly disseminated written documents.

NSP-Wisconsin undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

XML

Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	76
Net current period OCI	76
Accumulated other comprehensive loss at Dec. 31	$	(361	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Losses on cash flow hedges:
Interest rate derivatives	$	127		(a)
Total, pre-tax	127
Tax benefit	(51		)
Total amounts reclassified, net of tax	$	76

^(a)  Included in interest charges.

XML

Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2013 Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (in hundredths)	70.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	399

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Letters of Credit [Abstract]
Terms of letters of credit (in years)	1 year
Letters of credit outstanding under credit facilities	$ 0	$ 0

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0
Gain (Loss) on Fair Value Hedges Recognized in Earnings	0	0	0
Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(100,000)	(100,000)	(100,000)
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contract [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	(100,000)	(400,000)	(3,600,000)
Derivative Instruments Gain Loss Reclassified To Regulatory Assets And Liabilities Net	$ (700,000)	$ (2,900,000)	$ (2,900,000)

XML

Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2013
Commingled funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption (in days)	1
Commingled funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption (in days)	90
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption (in days)	45
Real estate funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption (in days)	90

XML

Commitments and Contingencies, Joint Operating System (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Counterparty
Joint Operating System [Abstract]
Number of companies covered by FERC approved Interchange Agreement	2
NSP-Minnesota | Nuclear Insurance [Member]
Joint Operating System [Abstract]
Maximum possible loss contingency	$ 13,600,000,000
Nuclear insurance coverage secured for the company's public liability exposure	375,000,000
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,200,000,000
Maximum assessments per reactor per accident	127,300,000
Number of owned and licensed reactors	3
Maximum funding requirement per reactor for any one year	19,000,000
Term for maximum installment payment assessment per reactor (in years)	1 year
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,300,000,000
Number of nuclear plant sites operated by NSP-Minnesota	2
Maximum assessments for business interruption insurance each calendar year	16,100,000
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	$ 40,200,000

XML

Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 2,390,241	$ 2,193,812
Less accumulated depreciation	(947,462)	(895,576)
Property, plant and equipment, net	1,442,779	1,298,236
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,913,354	1,795,239
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	236,047	224,625
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	112,886	111,319
CWIP
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 127,954	$ 62,629

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.4		1.2
Total unrecognized tax benefit	$	1.5	$	1.3

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

(Millions of Dollars)	2013			2012			2011
Balance at Jan. 1	$	1.3		$	1.5		$	1.9
Additions based on tax positions related to the current year	0.7			0.5			0.6
Reductions based on tax positions related to the current year	—			(0.2		)	(0.1		)
Additions for tax positions of prior years	0.5			0.3			0.7
Reductions for tax positions of prior years	—			(0.8		)	(0.3		)
Settlements with taxing authorities	(1.0		)	—			(1.2		)
Lapse of applicable statutes of limitations	—			—			(0.1		)
Balance at Dec. 31	$	1.5		$	1.3		$	1.5

Tax Benefits Associated with NOL and Tax Credit Carryforwards

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

(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(0.4	)	$	(0.9	)

NOL and Tax Credit Carryforwards

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)	2013	2012
Federal NOL carryforward	46.8	44.3
Federal tax credit carryforwards	4.4	8.0
State NOL carryforward	6.3	3.4

Schedule of Effective Income Tax Rate Reconciliation

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:

	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	5.0		3.4		4.4
Tax credits recognized	(0.9	)	(0.9	)	(0.9	)
Regulatory differences — utility plant items	(0.9	)	(0.3	)	0.5
Change in unrecognized tax benefits	—		0.1		(0.2	)
Other, net	(0.2	)	(0.1	)	0.9
Effective income tax rate	38.0	%	37.2	%	39.7	%

Schedule of Components of Income Tax Expense (Benefit)

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

(Thousands of Dollars)	2013			2012			2011
Current federal tax expense (benefit)	$	5,902		$	930		$	(1,540	)
Current state tax expense	4,628			2,216			1,573
Current change in unrecognized tax expense (benefit)	754			(69		)	(1,418		)
Deferred federal tax expense	23,794			25,089			30,251
Deferred state tax expense	2,720			1,890			4,105
Deferred change in unrecognized tax (benefit) expense	(725		)	128			1,254
Deferred investment tax credits	(664		)	(626		)	(611		)
Total income tax expense	$	36,409		$	29,558		$	33,614

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

(Thousands of Dollars)	2013			2012			2011
Deferred tax expense excluding items below	$	27,516		$	27,995		$	34,017
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,676		)	(837		)	1,644
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	25,789		$	27,107		$	35,610

Schedule of Deferred Tax Assets and Liabilities

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

(Thousands of Dollars)	2013		2012
Deferred tax liabilities:
Difference between book and tax bases of property	$	287,121	$	265,202
Regulatory assets	57,296		52,898
Employee benefits	16,953		16,862
Other	10,193		10,535
Total deferred tax liabilities	$	371,563	$	345,497
Deferred tax assets:
Environmental remediation	43,501		43,344
NOL carryforward	17,384		17,588
Regulatory liabilities	6,205		5,927
Deferred investment tax credits	5,976		5,766
Tax credit carryforward	4,440		8,011
Other	3,871		2,191
Total deferred tax assets	$	81,377	$	82,827
Net deferred tax liability	$	290,186	$	262,670

XML

Commitments and Contingencies, Guarantees (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Guarantee [Abstract]
Assets held as collateral	$ 0
Payment or Performance Guarantee [Member] | Customer Loans for Farm Rewiring Program [Member]
Guarantee [Abstract]
Guarantee amount	1.0	[1]
Current exposure	$ 0.3	[1]
Term or expiration date	2017	[1]

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

XML

Rate Matters (Details) (Public Service Commission of Wisconsin (PSCW), USD $) In Millions, unless otherwise specified	1 Months Ended
	Dec. 31, 2013	Oct. 31, 2013	May 31, 2013
Electric and Gas Rate Case 2014, Electric Rates
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 34.3
Public Utilities, Requested Rate Increase (Decrease), Amount			40.0
Public Utilities, Requested Rate Increase (Decrease), Percentage			6.50%
Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount			(4.5)
Public Utilities, Approved Rate Increase (Decrease), Amount	19.5
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.10%
Public Utilities, Approved Return on Equity, Percentage	10.20%
Public Utilities, Approved Equity Capital Structure, Percentage	52.50%
Public Utilities, Authorized Deferrals	4.1
Electric and Gas Rate Case 2014, Gas Rates
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		0
Public Utilities, Requested Rate Increase (Decrease), Amount			4.7
Public Utilities, Requested Rate Increase (Decrease), Percentage			3.80%
Electric and Gas Rate Case 2014
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Return on Equity, Percentage		10.40%	10.40%
Public Utilities, Requested Equity Capital Structure, Percentage			52.50%
Forecasted Average Net Investment Rate Base, Electric Utility			895.3
Forecasted Average Net Investment Rate Base, Natural Gas Utility			$ 89.8

XML

Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues
Electric	$ 136,917	$ 125,344	$ 124,334
Operating expenses
Purchased power	416,173	405,016	399,649
Transmission expense	42,460	44,942	40,870
Natural gas purchased for resale	97	116	98
Other operating expenses - paid to Xcel Energy Services Inc.	61,531	54,137	54,885
Interest expense	22	22	48
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	1,595	586
Accounts payable	24,986	31,556
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	18,584	26,632
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	8	71
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	26	0
Accounts payable	0	4
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	1,569	586
Accounts payable	$ 6,394	$ 4,849

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) (Pension Plans, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 136,935	$ 136,546	$ 121,348
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	8,865	11,933
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	118,269	109,719
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	9,801	14,894	15,807	17,801
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,332	7,956
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,332	7,956
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Derivatives
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	937	390
Derivatives | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Derivatives | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	937	390
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	6,711	9,406
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	6,711	9,406
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	24,955	25,046
Corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	24,955	25,046
Corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	307	749
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	307	0
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	749	1,578	1,367
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	684	2,128
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	684	0
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	2,128	3,781	5,984
Common stock
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,533	3,977
Common stock | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,533	3,977
Common stock | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Common stock | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,502	8,545
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,502	8,545	8,440	6,704
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	84,364	76,398
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	84,364	76,398
Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,299	3,472
Real estate | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,299	3,472	2,008	3,746
Securities lending collateral obligation and other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	311	(1,521)
Securities lending collateral obligation and other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Securities lending collateral obligation and other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	311	(1,521)
Securities lending collateral obligation and other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

XML

Commitments and Contingencies, Leases (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leases [Abstract]
Total expenses under operating lease obligations	$ 1.4	$ 1.1	$ 1.4
Other [Member]
Operating Leases, Future Minimum Payments Due [Abstract]
2014	0.8
2015	0.8
2016	0.8
2017	0.9
2018	0.9
Thereafter	8.8
Total	$ 13.0

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (437)
Accumulated other comprehensive loss at end of period	(361)		(437)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	(95,877)		(79,509)	(84,620)
Income Tax Expense (Benefit)	36,409		29,558	33,614
Gains and Losses on Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(437)
Losses reclassified from net accumulated other comprehensive loss	76
Net current period other comprehensive income (loss)	76
Accumulated other comprehensive loss at end of period	(361)
Gains and Losses on Cash Flow Hedges [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	127
Income Tax Expense (Benefit)	(51)
Total, net of tax	76
Gains and Losses on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	$ 127	[1]

[1] Included in interest charges.

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Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $) In Millions, unless otherwise specified		12 Months Ended	1 Months Ended
	Jun. 30, 2013 Federal Clean Water Act Regulation	Dec. 31, 2013 EPA GHG Regulation	Apr. 30, 2012 Electric Generating Unit Mercury And Air Toxics Standards Rule MW	Dec. 31, 2013 Capital Commitments Industrial Boiler Maximum Achievable Control Technology Rules
Environmental Requirements [Abstract]
Number of potential regulatory options under the proposed Effluent Limitations Guidelines rule	4
Number of issues granted review by the U.S. Supreme Court		1
Generating capacity (in MW)			25
Number of years before affected facilities must demonstrate compliance, low end of range			3 years
Number of years before affected facilities must demonstrate compliance, high end of range			4 years
Liability for estimated cost to comply with regulation				$ 17.2

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Segments and Related Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]
Intercompany revenue									$ 136,917		$ 125,344		$ 124,334
Operating revenues	240,388	231,060	210,175	241,415	217,395	226,475	194,173	223,799	923,038		861,842		875,790
Depreciation and amortization									76,897		69,234		68,574
Total interest charges and financing costs									25,816		22,937		23,993
Income Tax Expense (Benefit)									36,409		29,558		33,614
Net income	7,225	22,013	10,544	19,685	7,131	22,200	5,742	14,878	59,468		49,951		51,006
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									789,518		757,920		755,541
Depreciation and amortization									64,237		59,768		58,800
Total interest charges and financing costs									22,966		20,303		21,181
Income Tax Expense (Benefit)									33,691		27,164		32,656
Net income									51,334		45,377		47,093
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									134,834		103,827		121,028
Depreciation and amortization									12,485		9,251		9,599
Total interest charges and financing costs									2,749		2,554		2,675
Income Tax Expense (Benefit)									4,623		2,113		1,995
Net income									6,501		3,094		2,964
All Other
Segment Reporting Information [Line Items]
Operating revenues									1,003		1,177		1,207
Depreciation and amortization									175		215		175
Total interest charges and financing costs									101		80		137
Income Tax Expense (Benefit)									(1,905)		281		(1,037)
Net income									1,633		1,480		949
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues									923,038	[1]	861,842	[1]	875,790	[1]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									789,168	[1]	757,565	[1]	755,136	[1]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									132,867	[1]	103,100	[1]	119,447	[1]
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues									1,003	[1]	1,177	[1]	1,207	[1]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues									(2,317)		(1,082)		(1,986)
Depreciation and amortization									0		0		0
Total interest charges and financing costs									0		0		0
Income Tax Expense (Benefit)									0		0		0
Net income									0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									350		355		405
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									1,967		727		1,581
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues									$ 0		$ 0		$ 0

[1] Operating revenues include $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Commitments and Contingencies, Variable Interest Entities (Details) (Low-Income Housing Limited Partnerships [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Low-Income Housing Limited Partnerships [Member]
Amounts Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 223	$ 357
Property, plant and equipment, net	2,427	2,599
Other noncurrent assets	112	105
Total assets	2,762	3,061
Current liabilities	233	1,388
Mortgages and other long-term debt payable	1,687	617
Other noncurrent liabilities	42	39
Total liabilities	$ 1,962	$ 2,044

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Prepayments and other	$ 5,056		$ 4,394
Other current liabilities	9,376		10,955
Fair Value Measured on a Recurring Basis [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	580	[1]
Fair Value Measured on a Recurring Basis [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability			11	[2]
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	580
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability			11
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Prepayments and other	5,100
Other current liabilities			11,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	580
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability			11
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[3]
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability			$ 0	[3]

[1] Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.

[2] Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

[3] NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013 and 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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Segments and Related Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Information

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 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.

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 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.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2013
Operating revenues (a)	$	789,168	$	132,867	$	1,003		$	—		$	923,038
Intersegment revenues	350		1,967		—			(2,317		)	—
Total revenues	$	789,518	$	134,834	$	1,003		$	(2,317	)	$	923,038
Depreciation and amortization	$	64,237	$	12,485	$	175		$	—		$	76,897
Interest charges and financing costs	22,966		2,749		101			—			25,816
Income tax expense (benefit)	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	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 costs	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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2011
Operating revenues (a)	$	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 costs	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

^(a)  Operating revenuesinclude $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Borrowings and Other Financing Instruments,Other Short-Term Borrowings (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Notes payable to affiliates	$ 470	$ 550
Notes Payable, Other Payables
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 600
Weighted average interest rate at period end (in hundredths)	0.24%	0.33%

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	241,415	$	210,175	$	231,060	$	240,388
Operating income	37,401		22,466		40,769		16,545
Net income	19,685		10,544		22,013		7,225

	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

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Commitments and Contingencies, Fuel Contracts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Fuel Contracts [Abstract]
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs (in hundredths)	2.00%
Coal [Member]
Fuel Contracts [Abstract]
2014	$ 6.2
2015	1.3
2016	0.7
2017	0.7
2018	0.7
Thereafter	4.1
Total	13.7	[1]
Natural Gas Supply [Member]
Fuel Contracts [Abstract]
2014	13.4
2015	0.3
2016	0.3
2017	0.2
2018	0
Thereafter	0
Total	14.2	[1]
Natural Gas Storage and Transportation [Member]
Fuel Contracts [Abstract]
2014	11.9
2015	11.6
2016	11.7
2017	9.5
2018	4.4
Thereafter	18.9
Total	$ 68.0	[1]

[1] Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Purchases Under Fuel Contracts

The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2013 are as follows:

(Millions of dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	6.2	$	13.4	$	11.9
2015	1.3		0.3		11.6
2016	0.7		0.3		11.7
2017	0.7		0.2		9.5
2018	0.7		—		4.4
Thereafter	4.1		—		18.9
Total (a)	$	13.7	$	14.2	$	68.0

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

Future Commitments Under Operating Leases

Future commitments under operating leases are:

(Millions of Dollars)
2014	$	0.8
2015	0.8
2016	0.8
2017	0.9
2018	0.9
Thereafter	8.8
Total	$	13.0

Low-income Housing Limited Partnerships

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

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	223	$	357
Property, plant and equipment, net	2,427		2,599
Other noncurrent assets	112		105
Total assets	$	2,762	$	3,061
Current liabilities	$	233	$	1,388
Mortgages and other long-term debt payable	1,687		617
Other noncurrent liabilities	42		39
Total liabilities	$	1,962	$	2,044

Guarantee Issued and Outstanding

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	$	0.3	2017	(a)

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

Asset Retirement Obligations

A reconciliation of NSP-Wisconsin’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013 (a)
Electric plant
Steam production asbestos	$	1,962	$	—	$	43	$	—		$	2,005
Steam and other production ash containment	125		—		12		224			361
Electric distribution	13		—		1		22			36
Other	826		—		20		(557		)	289
Natural gas plant
Gas transmission and distribution	75		—		5		(5		)	75
Common and other property
Common miscellaneous	35		—		3		49			87
Total liability (b)	$	3,036	$	—	$	84	$	(267	)	$	2,853

(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Recognized		Accretion		Revisions to Prior Estimates		Ending Balance Dec. 31, 2012 (a)
Electric plant
Steam production asbestos	$	—	$	1,962	$	—	$	—	$	1,962
Steam and other production ash containment	120		—		5		—		125
Electric distribution	13		—		—		—		13
Other	186		—		7		633		826
Natural gas plant
Gas transmission and distribution	71		—		4		—		75
Common and other property
Common miscellaneous	34		—		1		—		35
Total liability (b)	$	424	$	1,962	$	17	$	633	$	3,036

^(a)  There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.

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

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Joint Ownership of Transmission Facilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 13,337
Accumulated depreciation	4,659
Construction work in progress	35,630
CapX2020 Transmission [Member] | Electric Transmission [Member]
Jointly Owned Utility Plant [Abstract]
Plant in service	13,337
Accumulated depreciation	4,659
Construction work in progress	30,199
Ownership % (in hundredths)	77.90%
La Crosse, Wis. to Madison, Wis. [Member] | Electric Transmission [Member]
Jointly Owned Utility Plant [Abstract]
Plant in service	0
Accumulated depreciation	0
Construction work in progress	$ 5,431
Ownership % (in hundredths)	50.00%

XML

Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Income and Expenses [Abstract]
Interest income	$ 538	$ 736	$ 324
Other nonoperating income	152	129	67
Insurance policy expense	(427)	(389)	(283)
Other nonoperating expense	(10)	0	(10)
Other income, net	$ 253	$ 476	$ 98

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) (Postretirement Benefit Plan)	12 Months Ended
	Dec. 31, 2013
Postretirement Benefit Plan
Postretirement Health Care Benefits [Abstract]
Amortization period for unrecognized accumulated postretirement benefit obligation (in years)	20 years

XML

Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Short-term Debt [Line Items]
Amount outstanding at period end	$ 68,000,000	$ 68,000,000	$ 39,000,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000,000	150,000,000	150,000,000	150,000,000
Amount outstanding at period end	68,000,000	68,000,000	39,000,000	66,000,000
Average amount outstanding	41,000,000	20,000,000	61,000,000	24,000,000
Maximum amount outstanding	$ 71,000,000	$ 71,000,000	$ 116,000,000	$ 70,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.30%	0.31%	0.39%	0.37%
Weighted average interest rate at period end (in hundredths)	0.27%	0.27%	0.40%	0.46%

XML

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2010	$ 502,678	$ 93,300	$ 187,071	$ 222,897	$ (590)
Balance (in shares) at Dec. 31, 2010		933,000
Comprehensive income:
Net income	51,006			51,006
Other comprehensive income	76				76
Common dividends declared to parent	(32,607)			(32,607)
Contribution of capital by parent	0		0
Ending Balance at Dec. 31, 2011	521,153	93,300	187,071	241,296	(514)
Balance (in shares) at Dec. 31, 2011		933,000
Comprehensive income:
Net income	49,951			49,951
Other comprehensive income	77				77
Common dividends declared to parent	(56,871)			(56,871)
Contribution of capital by parent	2,796		2,796
Ending Balance at Dec. 31, 2012	517,106	93,300	189,867	234,376	(437)
Balance (in shares) at Dec. 31, 2012	933,000	933,000
Comprehensive income:
Net income	59,468			59,468
Other comprehensive income	76				76
Common dividends declared to parent	(31,345)			(31,345)
Contribution of capital by parent	58,977		58,977
Ending Balance at Dec. 31, 2013	$ 604,282	$ 93,300	$ 248,844	$ 262,499	$ (361)
Balance (in shares) at Dec. 31, 2013	933,000	933,000

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 746	$ 647	$ 746
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	31	123
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	715	469
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	55	62	51
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	31	123
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	31	123
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Derivatives
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(2)
Derivatives | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0
Derivatives | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(2)
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	89	99
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	89	99
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	80	67
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	80	67
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	79	59
Corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	79	59
Corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5	1
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5	0
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	1	14	6
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	37	54
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	37	0
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	54	48	45
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	452	307
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	452	307
Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(25)	(63)
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(25)	(63)
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

XML

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue Recognition [Abstract]
Number of years between rate review processes (in years)	2 years
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs	2.00%
Property, Plant and Equipment and Depreciation [Abstract]
Depreciation expense expressed as a percentage of average depreciable property (in hundredths)	3.50%	3.50%	3.60%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents (in months)	3 months

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Business and System of Accounts

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

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

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

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

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.

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.

Conservation Programs

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 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 required to be decommissioned early by a regulator 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, 3.5 and 3.6 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

Leases

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— AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing 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

AROs — 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 effective 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.

Income Taxes

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

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.

Fair Value Measurements

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

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 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

Inventory— All inventory is recorded at average cost.

Renewable Energy Credits

RECs — 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 — 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. 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— Environmental costs are recorded when it is probable NSP-Wisconsin is liable for remediation 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

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

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.

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

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

XML

Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	241,415	$	210,175	$	231,060	$	240,388
Operating income	37,401		22,466		40,769		16,545
Net income	19,685		10,544		22,013		7,225

	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

XML

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 600,000	$ 600,000
Pension Plans
Pension Benefits [Abstract]
Total benefit obligation	163,930,000	179,995,000	159,766,000
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years)	20 years
Expected average long-term rate of return on assets (in hundredths)	7.25%	7.50%	8.00%
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	7.25%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	100.00%	100.00%
Pension Plans | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	31.00%	29.00%
Pension Plans | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	29.00%	30.00%
Pension Plans | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	16.00%	12.00%
Pension Plans | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	22.00%	27.00%
Pension Plans | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (in hundredths)	2.00%	2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	36,500,000	39,400,000
Net benefit cost recognized for financial reporting	$ 6,600,000	$ 15,600,000

XML

Selected Balance Sheet Data, Accounts Receivable (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Accounts Receivable, Net
Accounts receivable	$ 64,180		$ 55,039
Less allowance for bad debts	(4,911)		(4,333)
Accounts receivable, net	59,269	[1]	50,706	[1]
Accounts receivable from affiliates, net	$ 1,595		$ 586

[1] Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

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Selected Balance Sheet Data (Tables)

12 Months Ended

Dec. 31, 2013

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Accounts receivable, net (a)
Accounts receivable	$	64,180		$	55,039
Less allowance for bad debts	(4,911		)	(4,333		)
	$	59,269		$	50,706

^(a)  Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

Inventories

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	6,437	$	6,172
Fuel	5,915		6,664
Natural gas	9,123		6,849
	$	21,475	$	19,685

Property, Plant and Equipment, Net

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	1,913,354		$	1,795,239
Natural gas plant	236,047			224,625
Common and other property	112,886			111,319
CWIP	127,954			62,629
Total property, plant and equipment	2,390,241			2,193,812
Less accumulated depreciation	(947,462		)	(895,576		)
	$	1,442,779		$	1,298,236

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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Borrowings and Other Financing Instruments [Abstract]

Committed Credit Facility Available

At Dec. 31, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	68.0	$	82.0

^(a)  Credit facility expires in July 2017.

^(b)  Includes outstanding commercial paper.

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

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. Commercial paper outstanding for NSP-Wisconsin was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2013
Borrowing limit	$	150
Amount outstanding at period end	68
Average amount outstanding	41
Maximum amount outstanding	71
Weighted average interest rate, computed on a daily basis	0.30		%
Weighted average interest rate at period end	0.27

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	68			39			66
Average amount outstanding	20			61			24
Maximum amount outstanding	71			116			70
Weighted average interest rate, computed on a daily basis	0.31		%	0.39		%	0.37		%
Weighted average interest rate at period end	0.27			0.40			0.46

Notes Payable, Other Payables

Borrowings and Other Financing Instruments [Abstract]

Short-term Borrowings

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, 2013			Dec. 31, 2012
Notes payable to affiliates	$	0.5		$	0.6
Weighted average interest rate	0.24		%	0.33		%

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Capitalization
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, par value (in dollars per share)	$ 100	$ 100
Common stock, shares outstanding (in shares)	933,000	933,000

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Joint Ownership of Transmission Facilities (Tables)

12 Months Ended

Dec. 31, 2013

Joint Ownership of Transmission Facilities [Abstract]

Investments in Jointly Owned Transmission Facilities

Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2013:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	13,337	$	4,659	$	30,199	77.9	%
La Crosse, Wis. to Madison, Wis.	—		—		5,431		50.0
Total NSP-Wisconsin	$	13,337	$	4,659	$	35,630

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Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) (Plant Removal Costs, USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 116	$ 114

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Results from Continuing Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2013
Operating revenues (a)	$	789,168	$	132,867	$	1,003		$	—		$	923,038
Intersegment revenues	350		1,967		—			(2,317		)	—
Total revenues	$	789,518	$	134,834	$	1,003		$	(2,317	)	$	923,038
Depreciation and amortization	$	64,237	$	12,485	$	175		$	—		$	76,897
Interest charges and financing costs	22,966		2,749		101			—			25,816
Income tax expense (benefit)	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	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 costs	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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2011
Operating revenues (a)	$	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 costs	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

^(a)  Operating revenuesinclude $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Income Taxes (Details) (USD $)	12 Months Ended			1 Months Ended	3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Internal Revenue Service (IRS)	Sep. 30, 2012 Internal Revenue Service (IRS)	Dec. 31, 2013 Internal Revenue Service (IRS)	Dec. 31, 2012 Internal Revenue Service (IRS)	Mar. 31, 2013 State and Local Jurisdiction	Dec. 31, 2013 State and Local Jurisdiction	Dec. 31, 2012 State and Local Jurisdiction
Tax Audits [Abstract]
Year(s) no longer subject to audit as statute of limitations has expired						2008
Earliest year subject to examination						2009			2009
Year(s) under examination					2010 and 2011			2009 through 2011
Tax Adjustments, Settlements, and Unusual Provisions				$ 10,000,000
Operating Loss Carryforwards				46,800,000		46,800,000	44,300,000		6,300,000	3,400,000
Tax Credit Carryforward, Amount				4,400,000		4,400,000	8,000,000
Carryforward expiration date range, low						2021			2022
Carryforward expiration date range, high						2033			2031
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions	100,000	100,000
Unrecognized tax benefit — Temporary tax positions	1,400,000	1,200,000
Total unrecognized tax benefit	1,500,000	1,300,000	1,500,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1	1,300,000	1,500,000	1,900,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	700,000	500,000	600,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	0	(200,000)	(100,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions	500,000	300,000	700,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions	0	(800,000)	(300,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	(1,000,000)	0	(1,200,000)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	(100,000)
Balance at Dec. 31	1,500,000	1,300,000	1,500,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards	(400,000)	(900,000)
Amounts accrued for penalties related to unrecognized tax benefits	0	0	0
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	5.00%	3.40%	4.40%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	(0.90%)	(0.90%)	(0.90%)
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items	(0.90%)	(0.30%)	0.50%
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits	0.00%	0.10%	(0.20%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent	(0.20%)	(0.10%)	0.90%
Effective Income Tax Rate Reconciliation, Percent	38.00%	37.20%	39.70%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	5,902,000	930,000	(1,540,000)
Current State and Local Tax Expense (Benefit)	4,628,000	2,216,000	1,573,000
Current Change In Unrecognized Tax Expense (Benefit)	754,000	(69,000)	(1,418,000)
Deferred Federal Income Tax Expense (Benefit)	23,794,000	25,089,000	30,251,000
Deferred State and Local Income Tax Expense (Benefit)	2,720,000	1,890,000	4,105,000
Deferred Change In Unrecognized Tax Expense (Benefit)	(725,000)	128,000	1,254,000
Deferred investment tax credits	(664,000)	(626,000)	(611,000)
Income Tax Expense (Benefit)	36,409,000	29,558,000	33,614,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items	27,516,000	27,995,000	34,017,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,676,000)	(837,000)	1,644,000
Other Comprehensive Income (Loss), Tax	(51,000)	(51,000)	(51,000)
Deferred Income Tax Expense (Benefit)	25,789,000	27,107,000	35,610,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	287,121,000	265,202,000
Deferred Tax Liabilities, Regulatory Assets	57,296,000	52,898,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits	16,953,000	16,862,000
Deferred Tax Liabilities, Other	10,193,000	10,535,000
Deferred Tax Liabilities, Net	371,563,000	345,497,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Environmental Remediation	43,501,000	43,344,000
Deferred Tax Assets, Operating Loss Carryforwards	17,384,000	17,588,000
Deferred Tax Assets Regulatory Liabilities	6,205,000	5,927,000
Deferred Tax Assets Deferred Investment Tax Credits	5,976,000	5,766,000
Deferred Tax Assets Tax credit carryforward	4,440,000	8,011,000
Deferred Tax Assets, Other	3,871,000	2,191,000
Deferred Tax Assets, Net of Valuation Allowance	81,377,000	82,827,000
Deferred Tax Assets, Net	$ 290,186,000	$ 262,670,000

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 468,597	$ 468,563
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 518,269	$ 576,353

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues
Electric	$ 789,168	$ 757,565	$ 755,136
Natural gas	132,867	103,100	119,447
Other	1,003	1,177	1,207
Total operating revenues	923,038	861,842	875,790
Operating expenses
Electric fuel and purchased power, non-affiliates	18,129	19,440	20,957
Purchased power, affiliates	416,173	405,016	399,649
Cost of natural gas sold and transported	81,572	61,370	78,208
Operating and maintenance expenses	175,522	167,503	164,323
Conservation program expenses	12,333	14,442	12,883
Depreciation and amortization	76,897	69,234	68,574
Taxes (other than income taxes)	25,231	24,971	23,688
Total operating expenses	805,857	761,976	768,282
Operating income	117,181	99,866	107,508
Other income, net	253	476	98
Allowance for funds used during construction — equity	4,259	2,104	1,007
Interest charges and financing costs
Interest charges — includes other financing costs of $1,538, $1,574 and $1,713, respectively	27,797	24,799	24,168
Allowance for funds used during construction — debt	(1,981)	(1,862)	(175)
Total interest charges and financing costs	25,816	22,937	23,993
Income before income taxes	95,877	79,509	84,620
Income taxes	36,409	29,558	33,614
Net income	$ 59,468	$ 49,951	$ 51,006

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Selected Balance Sheet Data, Inventory (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Public Utilities, Inventory [Line Items]
Inventories	$ 21,475	$ 19,685
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	6,437	6,172
Fuel
Public Utilities, Inventory [Line Items]
Inventories	5,915	6,664
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 9,123	$ 6,849

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities
Net income	$ 59,468	$ 49,951	$ 51,006
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	78,048	70,372	69,900
Deferred income taxes	25,789	27,107	35,610
Amortization of investment tax credits	(664)	(626)	(611)
Allowance for equity funds used during construction	(4,259)	(2,104)	(1,007)
Provision for bad debts	3,988	3,329	3,842
Net derivative (gains) losses	(279)	127	127
Changes in operating assets and liabilities:
Accounts receivable	(12,702)	(15,953)	(4,013)
Accrued unbilled revenues	(2,496)	(470)	2,911
Inventories	(1,879)	6,018	913
Other current assets	(3,749)	(3,172)	(1,180)
Accounts payable	(1,811)	5,828	(16,614)
Net regulatory assets and liabilities	(2,062)	3,623	10,008
Other current liabilities	7,589	3,681	(2,260)
Pension and other employee benefit obligations	(8,759)	(10,857)	(7,214)
Change in other noncurrent assets	232	14	564
Change in other noncurrent liabilities	1,119	(595)	(2,682)
Net cash provided by operating activities	137,573	136,273	139,300
Investing activities
Utility capital/construction expenditures	(201,278)	(152,759)	(140,982)
Allowance for equity funds used during construction	4,259	2,104	1,007
Other, net	(421)	916	(112)
Net cash used in investing activities	(197,440)	(149,739)	(140,087)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	29,000	(27,000)	66,000
Proceeds from notes payable to affiliates	0	50	111,300
Repayments Of Notes Payable To Affiliates	(80)	0	(148,350)
Proceeds from Issuance of Long-term Debt	0	97,916	0
Repayments of long-term debt	(160)	(97)	(96)
Capital contributions from parent	58,977	2,796	0
Dividends paid to parent	(30,980)	(57,311)	(32,941)
Net cash provided by (used in) financing activities	56,757	16,354	(4,087)
Net change in cash and cash equivalents	(3,110)	2,888	(4,874)
Cash and cash equivalents at beginning of period	4,459	1,571	6,445
Cash and cash equivalents at end of period	1,349	4,459	1,571
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(24,376)	(21,035)	(22,616)
Cash (paid) received for income taxes, net	(9,842)	(5,841)	1,116
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 27,222	$ 10,618	$ 9,427

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Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (Pension Plans, USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31		$ 153,894,000		$ 169,939,000
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	163,930,000	179,995,000		159,766,000
Service cost		5,682,000		4,568,000		4,271,000
Interest cost		6,924,000		7,765,000		8,031,000
Plan amendments		(1,109,000)		216,000
Actuarial (gain) loss		(11,097,000)		21,083,000
Benefit payments		(16,465,000)		(13,403,000)
Obligation at Dec. 31		163,930,000		179,995,000		159,766,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	136,935,000	136,546,000		121,348,000
Actual return (loss) on plan assets		5,525,000		16,079,000
Employer contributions		11,329,000		12,522,000
Benefit payments		(16,465,000)		(13,403,000)
Fair value of plan assets at Dec. 31		136,935,000		136,546,000		121,348,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(26,995,000)	[1]	(43,449,000)	[1]
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		84,773,000		99,338,000
Prior service (credit) cost		778,000		2,290,000
Total		85,551,000		101,628,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets		7,631,000		6,895,000
Noncurrent regulatory assets		77,920,000		94,733,000
Total		85,551,000		101,628,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date		12/31/2013		12/31/2012
Discount rate for year-end valuation (in hundredths)		4.75%		4.00%
Expected average long-term increase in compensation level (in hundredths)		3.75%		3.75%
Mortality table		RP 2000		RP 2000
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period	8,000,000	11,300,000		12,500,000		6,400,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		5,682,000		4,568,000		4,271,000
Interest cost		6,924,000		7,765,000		8,031,000
Expected return on plan assets		(9,995,000)		(10,489,000)		(11,484,000)
Amortization of prior service cost (credit)		417,000		1,771,000		1,895,000
Amortization of net loss		7,924,000		6,004,000		4,070,000
Net periodic benefit cost		10,952,000		9,619,000		6,783,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (in hundredths)		4.00%		5.00%		5.50%
Expected average long-term increase in compensation level (in hundredths)		3.75%		4.00%		4.00%
Expected average long-term rate of return on assets (in hundredths)		7.25%		7.50%		8.00%
Allocated costs for pension plans sponsored by Xcel Energy Inc.		2,200,000		1,800,000		1,300,000
Expected average long-term rate of return on assets for next fiscal year (in hundredths)		7.25%
Number of years fair market value of plan assets is adjusted using calculated value method (in years)		5 years
Annual adjustment rate used in calculated value method (in hundredths)		20.00%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period	$ 130,000,000	$ 192,400,000		$ 198,100,000		$ 137,300,000
Number of pension plans to which contributions were made	3	4		4		3

[1] Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.

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Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Other Income, Net

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

(Thousands of Dollars)	2013			2012			2011
Interest income	$	538		$	736		$	324
Other nonoperating income	152			129			67
Insurance policy expense	(427		)	(389		)	(283		)
Other nonoperating expense	(10		)	—			(10		)
Other income, net	$	253		$	476		$	98

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Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Pension Plans
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2014	$ 21,677
2015	14,257
2016	13,420
2017	13,851
2018	12,983
2019-2023	64,935
Postretirement Benefit Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2014	1,491
2015	1,459
2016	1,444
2017	1,384
2018	1,357
2019-2023	6,229
Expected Medicare Part D Subsidies [Abstract]
2014	27
2015	25
2016	24
2017	20
2018	18
2019-2023	82
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2014	1,464
2015	1,434
2016	1,420
2017	1,364
2018	1,339
2019-2023	$ 6,147

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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.

CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including the NSP System that has proposed several groups of transmission projects to be completed 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 entered into various long-term commitments 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 2014 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 for future rate recovery or refund when fuel costs differ from the amount included in rates by more than two percent on an annual basis, as determined by the PSCW after an opportunity for a hearing and an earnings test based on NSP-Wisconsin’s authorized ROE.

The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2013 are as follows:

(Millions of dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	6.2	$	13.4	$	11.9
2015	1.3		0.3		11.6
2016	0.7		0.3		11.7
2017	0.7		0.2		9.5
2018	0.7		—		4.4
Thereafter	4.1		—		18.9
Total (a)	$	13.7	$	14.2	$	68.0

^(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.

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 $1.4 million, $1.1 million and $1.4 million for 2013, 2012 and 2011, respectively.

Future commitments under operating leases are:

(Millions of Dollars)
2014	$	0.8
2015	0.8
2016	0.8
2017	0.9
2018	0.9
Thereafter	8.8
Total	$	13.0

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.

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

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	223	$	357
Property, plant and equipment, net	2,427		2,599
Other noncurrent assets	112		105
Total assets	$	2,762	$	3,061
Current liabilities	$	233	$	1,388
Mortgages and other long-term debt payable	1,687		617
Other noncurrent liabilities	42		39
Total liabilities	$	1,962	$	2,044

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 $13.6 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 $13.2 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 $127.3 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 $19 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 September 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites.  NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units.  Premiums are expensed over the policy term.  All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds.  Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.  However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $40.2 million for property damage insurance if losses exceed accumulated reserve funds.

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	$	0.3	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/Northern States Power Lakefront Superfund Site (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. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.

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 settlement negotiations with NSP-Wisconsin, 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 has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy 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. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. NSP-Wisconsin is in the process of negotiating a final pilot study work plan for possible implementation in late summer or early fall of 2014.

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 is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At Dec. 31, 2013 and 2012, NSP-Wisconsin had recorded a liability of $104.6 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $25.2 million and $20.1 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.

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 historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and 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 three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 clean-up costs for the Phase I Project Area. The PSCW determined the timing of the clean-up of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the clean-up in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the clean-up by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

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 two 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 $3.9 million and $2.5 million for both of these sites at Dec. 31, 2013 and 2012, 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.

Environmental Requirements

Water and waste

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.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Federal 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. A final rule is anticipated in April 2014. 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 entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Air

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. 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. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. 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 Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO₂ emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, 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 the re-proposed NSPS until its final requirements are known.

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 D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.

As 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 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At Dec. 31, 2013, 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 will not have any units subject to EGU MATS because it will cease coal combustion in Bay Front Unit 5.

Industrial Boiler (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 anticipated to be $17.2 million in total and is 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.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, other and hydro), electric distribution and transmission, natural gas transmission and distribution, and general property.  The electric production obligations include ash-containment facilities, storage tanks, control panels and 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.  The common general AROs include small obligations related to storage tanks and office buildings. These 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, 2013 and 2012, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013 (a)
Electric plant
Steam production asbestos	$	1,962	$	—	$	43	$	—		$	2,005
Steam and other production ash containment	125		—		12		224			361
Electric distribution	13		—		1		22			36
Other	826		—		20		(557		)	289
Natural gas plant
Gas transmission and distribution	75		—		5		(5		)	75
Common and other property
Common miscellaneous	35		—		3		49			87
Total liability (b)	$	3,036	$	—	$	84	$	(267	)	$	2,853

(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Recognized		Accretion		Revisions to Prior Estimates		Ending Balance Dec. 31, 2012 (a)
Electric plant
Steam production asbestos	$	—	$	1,962	$	—	$	—	$	1,962
Steam and other production ash containment	120		—		5		—		125
Electric distribution	13		—		—		—		13
Other	186		—		7		633		826
Natural gas plant
Gas transmission and distribution	71		—		4		—		75
Common and other property
Common miscellaneous	34		—		1		—		35
Total liability (b)	$	424	$	1,962	$	17	$	633	$	3,036

^(a)  There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.

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

In 2013, NSP-Wisconsin revised ash containment facilities, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and common general AROs due to revised estimated cash flows. In 2012, 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, 2013 and 2012 were $116 million and $114 million, respectively.

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.

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

The following table details the gross notional amounts of commodity options at Dec. 31, 2013 and 2012:

(Amounts in Thousands)(a)(b)	Dec. 31, 2013	Dec. 31, 2012
MMBtu of natural gas	987	53

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

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

Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss

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)	2013			2012			2011
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(437	)	$	(514	)	$	(590	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			77			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(361	)	$	(437	)	$	(514	)

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

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

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	580	$	—	$	580	$	—	$	580

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

^(a)  NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013 and 2012.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.

^(c)  Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

Carrying Amount and Fair Value of Long-term Debt

As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2013				2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,597	$	518,269	$	468,563	$	576,353

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	76
Net current period OCI	76
Accumulated other comprehensive loss at Dec. 31	$	(361	)

Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Losses on cash flow hedges:
Interest rate derivatives	$	127		(a)
Total, pre-tax	127
Tax benefit	(51		)
Total amounts reclassified, net of tax	$	76

^(a)  Included in interest charges.

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 MMBTU		Dec. 31, 2012 MMBTU
Interest Rate Contract [Member]
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	$ (0.1)
Natural Gas Commodity Contract [Member]
Gross Notional Amounts of Commodity Options [Abstract]
Notional amount	987,000	[1],[2]	53,000	[1],[2]

[1] Amounts are not reflective of net positions in the underlying commodities.

[2] Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 1,349		$ 4,459
Accounts receivable, net	59,269	[1]	50,706	[1]
Accrued unbilled revenues	51,634		49,138
Inventories	21,475		19,685
Regulatory assets	14,866		12,048
Prepaid taxes	27,518		24,688
Deferred income taxes	14,953		0
Prepayments and other	5,056		4,394
Total current assets	196,120		165,118
Property, plant and equipment, net	1,442,779		1,298,236
Other assets
Regulatory assets	233,193		240,459
Other investments	3,650		3,232
Other	3,651		4,040
Total other assets	240,494		247,731
Total assets	1,879,393		1,711,085
Current liabilities
Current portion of long-term debt	107		1,246
Short-term debt	68,000		39,000
Notes payable to affiliates	470		550
Accounts payable	52,086		30,723
Accounts payable to affiliates	24,986		31,556
Dividends payable to parent	8,032		7,667
Regulatory liabilities	9,717		6,086
Taxes accrued	5,638		839
Environmental liabilities	28,785		23,427
Accrued interest	7,507		7,304
Other	9,376		10,955
Total current liabilities	214,704		159,353
Deferred credits and other liabilities
Deferred income taxes	305,139		261,800
Deferred investment tax credits	9,698		8,911
Regulatory liabilities	126,424		123,746
Environmental liabilities	79,703		84,655
Customer advances	16,008		15,631
Pension and employee benefit obligations	45,708		63,643
Other	9,237		8,923
Total deferred credits and other liabilities	591,917		567,309
Commitments and contingencies
Capitalization
Long-term debt	468,490		467,317
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2013 and 2012, respectively	93,300		93,300
Additional paid in capital	248,844		189,867
Retained earnings	262,499		234,376
Accumulated other comprehensive loss	(361)		(437)
Total common stockholder’s equity	604,282		517,106
Total liabilities and equity	$ 1,879,393		$ 1,711,085

[1] Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest charges and financing costs
Other financing costs	$ 1,538	$ 1,574	$ 1,713

XML

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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 June 2015.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution are uncertain.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2013, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011. As of Dec. 31, 2013, no material adjustments had been proposed for these years.  There are currently no other state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	1.4		1.2
Total unrecognized tax benefit	$	1.5	$	1.3

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

(Millions of Dollars)	2013			2012			2011
Balance at Jan. 1	$	1.3		$	1.5		$	1.9
Additions based on tax positions related to the current year	0.7			0.5			0.6
Reductions based on tax positions related to the current year	—			(0.2		)	(0.1		)
Additions for tax positions of prior years	0.5			0.3			0.7
Reductions for tax positions of prior years	—			(0.8		)	(0.3		)
Settlements with taxing authorities	(1.0		)	—			(1.2		)
Lapse of applicable statutes of limitations	—			—			(0.1		)
Balance at Dec. 31	$	1.5		$	1.3		$	1.5

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

(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(0.4	)	$	(0.9	)

It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As NSP-Wisconsin had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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)	2013	2012
Federal NOL carryforward	46.8	44.3
Federal tax credit carryforwards	4.4	8.0
State NOL carryforward	6.3	3.4

The federal carryforward periods expire between 2021 and 2033.  The state carryforward periods expire between 2022 and 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:

	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	5.0		3.4		4.4
Tax credits recognized	(0.9	)	(0.9	)	(0.9	)
Regulatory differences — utility plant items	(0.9	)	(0.3	)	0.5
Change in unrecognized tax benefits	—		0.1		(0.2	)
Other, net	(0.2	)	(0.1	)	0.9
Effective income tax rate	38.0	%	37.2	%	39.7	%

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

(Thousands of Dollars)	2013			2012			2011
Current federal tax expense (benefit)	$	5,902		$	930		$	(1,540	)
Current state tax expense	4,628			2,216			1,573
Current change in unrecognized tax expense (benefit)	754			(69		)	(1,418		)
Deferred federal tax expense	23,794			25,089			30,251
Deferred state tax expense	2,720			1,890			4,105
Deferred change in unrecognized tax (benefit) expense	(725		)	128			1,254
Deferred investment tax credits	(664		)	(626		)	(611		)
Total income tax expense	$	36,409		$	29,558		$	33,614

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

(Thousands of Dollars)	2013			2012			2011
Deferred tax expense excluding items below	$	27,516		$	27,995		$	34,017
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,676		)	(837		)	1,644
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	25,789		$	27,107		$	35,610

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

(Thousands of Dollars)	2013		2012
Deferred tax liabilities:
Difference between book and tax bases of property	$	287,121	$	265,202
Regulatory assets	57,296		52,898
Employee benefits	16,953		16,862
Other	10,193		10,535
Total deferred tax liabilities	$	371,563	$	345,497
Deferred tax assets:
Environmental remediation	43,501		43,344
NOL carryforward	17,384		17,588
Regulatory liabilities	6,205		5,927
Deferred investment tax credits	5,976		5,766
Tax credit carryforward	4,440		8,011
Other	3,871		2,191
Total deferred tax assets	$	81,377	$	82,827
Net deferred tax liability	$	290,186	$	262,670

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 24, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO /WI/
Entity Central Index Key	0000072909
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q4
Amendment Flag	false
Entity Common Stock, Shares Outstanding		933,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

XML

Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

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, 2013, NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016.

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.

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.

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.

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.

Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

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, 2013 and 2012 were $36.5 million and $39.4 million, respectively, of which $0.6 million and $0.6 million, respectively, was attributable to NSP-Wisconsin. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 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 2013 were below the assumed level of 7.25 percent. Investment returns in 2012 were above the assumed level of 7.50 percent while returns in 2011 were below the assumed level of 8.00 percent. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions. In 2014, 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:

	2013		2012
Domestic and international equity securities	31	%	29	%
Long-duration fixed income and interest rate swap securities	29		30
Short-to-intermediate term fixed income securities	16		12
Alternative investments	22		27
Cash	2		2
Total	100	%	100	%

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, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	4,332	$	—	$	—	$	4,332
Derivatives	—		937		—		937
Government securities	—		6,711		—		6,711
Corporate bonds	—		24,955		—		24,955
Asset-backed securities	—		307		—		307
Mortgage-backed securities	—		684		—		684
Common stock	4,533		—		—		4,533
Private equity investments	—		—		7,502		7,502
Commingled funds	—		84,364		—		84,364
Real estate	—		—		2,299		2,299
Securities lending collateral obligation and other	—		311		—		311
Total	$	8,865	$	118,269	$	9,801	$	136,935

	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

The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	749	$	—		$	—		$	—		$	(749	)	$	—
Mortgage-backed securities	2,128		—			—			—			(2,128		)	—
Private equity investments	8,545		1,083			(1,960		)	(166		)	—			7,502
Real estate	3,472		(129		)	247			450			(1,741		)	2,299
Total	$	14,894	$	954		$	(1,713	)	$	284		$	(4,618	)	$	9,801

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		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

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		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

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)	2013			2012
Accumulated Benefit Obligation at Dec. 31	$	153,894		$	169,939
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	179,995		$	159,766
Service cost	5,682			4,568
Interest cost	6,924			7,765
Plan amendments	(1,109		)	216
Actuarial (gain) loss	(11,097		)	21,083
Benefit payments	(16,465		)	(13,403		)
Obligation at Dec. 31	$	163,930		$	179,995

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	136,546		$	121,348
Actual return on plan assets	5,525			16,079
Employer contributions	11,329			12,522
Benefit payments	(16,465		)	(13,403		)
Fair value of plan assets at Dec. 31	$	136,935		$	136,546

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(26,995	)	$	(43,449	)

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

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	84,773	$	99,338
Prior service cost	778		2,290
Total	$	85,551	$	101,628

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	7,631	$	6,895
Noncurrent regulatory assets	77,920		94,733
Total	$	85,551	$	101,628

Measurement date Dec. 31, 2013 Dec. 31, 2012

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75
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, 2012 and 2013 to meet minimum funding requirements.

The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014:

• In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $8.0 million was attributable to NSP-Wisconsin;

• In 2013, contributions of $192.4 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 2013 resulting in a decrease of the projected benefit obligation due to fully insuring the long-term disability benefit for NSP bargaining participants. This decrease was partially offset by an increase to the projected benefit obligation resulting from a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan. In 2012, the plan was amended 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)	2013			2012			2011
Service cost	$	5,682		$	4,568		$	4,271
Interest cost	6,924			7,765			8,031
Expected return on plan assets	(9,995		)	(10,489		)	(11,484		)
Amortization of prior service cost	417			1,771			1,895
Amortization of net loss	7,924			6,004			4,070
Net periodic pension cost	$	10,952		$	9,619		$	6,783

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.00	%	5.00	%	5.50	%
Expected average long-term increase in compensation level	3.75		4.00		4.00
Expected average long-term rate of return on assets	7.25		7.50		8.00

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 $2.2 million, $1.8 million and $1.3 million in 2013, 2012 and 2011, 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 2014 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 expense to these plans for NSP-Wisconsin was approximately $1.3 million in 2013, $1.2 million in 2012 and $1.1 million in 2011.

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 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, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	31	$	—		$	—	$	31
Derivatives	—		(2		)	—		(2		)
Government securities	—		89			—		89
Insurance contracts	—		80			—		80
Corporate bonds	—		79			—		79
Asset-backed securities	—		5			—		5
Mortgage-backed securities	—		37			—		37
Commingled funds	—		452			—		452
Other	—		(25		)	—		(25		)
Total	$	31	$	715		$	—	$	746

	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

The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	1	$	—	$	—	$	—	$	(1	)	$	—
Mortgage-backed securities	54		—		—		—		(54		)	—
Total	$	55	$	—	$	—	$	—	$	(55	)	$	—

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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

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

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)	2013			2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	19,432		$	22,127
Service cost	25			20
Interest cost	760			1,075
Medicare subsidy reimbursements	31			189
Plan amendments	—			(3,440		)
Plan participants’ contributions	621			893
Actuarial (gain) loss	(1,724		)	1,486
Benefit payments	(1,992		)	(2,918		)
Obligation at Dec. 31	$	17,153		$	19,432

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	647		$	746
Actual return on plan assets	(13		)	3
Plan participants’ contributions	621			893
Employer contributions	1,483			1,923
Benefit payments	(1,992		)	(2,918		)
Fair value of plan assets at Dec. 31	$	746		$	647

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status	$	(16,407	)	$	(18,785	)
Current liabilities	(718		)	(943		)
Noncurrent liabilities	(15,689		)	(17,842		)
Net postretirement amounts recognized on consolidated balance sheets	$	(16,407	)	$	(18,785	)

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	11,098		$	13,730
Prior service credit	(3,187		)	(3,538		)
Transition obligation	—			1
Total	$	7,911		$	10,193

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	570	$	433
Noncurrent regulatory assets	7,341		9,760
Total	$	7,911	$	10,193

Measurement date Dec. 31, 2013 Dec. 31, 2012

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.82	%	4.10	%
Mortality table	RP 2000		RP 2000
Health care costs trend rate — initial	7.00	%	7.50	%

Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five 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 one-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	$	1,773	$	(1,486	)
Service and interest components	78		(61		)

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 $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $1.5 million, $1.9 million and $2.4 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which $1.5 million is attributable to NSP-Wisconsin.

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)	2013			2012			2011
Service cost	$	25		$	20		$	17
Interest cost	760			1,075			1,144
Expected return on plan assets	(42		)	(50		)	(74		)
Amortization of transition obligation	1			171			171
Amortization of prior service credit	(351		)	(14		)	(14		)
Amortization of net loss	963			486			366
Net periodic postretirement benefit cost	$	1,356		$	1,688		$	1,610

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.10	%	5.00	%	5.50	%
Expected average long-term rate of return on assets	7.11		6.75		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)	ProjectedPension BenefitPayments		Gross Projected Postretirement Health Care BenefitPayments		ExpectedMedicare Part DSubsidies		Net Projected Postretirement Health Care BenefitPayments
2014	$	21,677	$	1,491	$	27	$	1,464
2015	14,257		1,459		25		1,434
2016	13,420		1,444		24		1,420
2017	13,851		1,384		20		1,364
2018	12,983		1,357		18		1,339
2019-2023	64,935		6,229		82		6,147

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, 2013, 2012 and 2011.  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)	2013		2012		2011
Multiemployer plan contributions:
Pension	$	130	$	163	$	169
Total	$	130	$	163	$	169

XML

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Site	Dec. 31, 2012
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites, current	$ 28,785,000	$ 23,427,000
Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties included in superfund site which NSP-Wisconsin does not own	2
Liability for estimated cost of remediating sites	104,600,000	103,700,000
Liability for estimated cost of remediating sites, current	25,200,000	20,100,000
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years)	4 years
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years)	6 years
Ashland MGP Site - Phase I Project Area
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites	40,000,000
Number of acres of land conveyed to the State of Wisconsin and tribal trustees (in acres)	1,390
Approved amortization period for recovery of remediation costs in natural gas rates (in years)	10 years
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths)	3.00%
Approved increase (decrease) in amortization expense granted by a regulatory body	1,100,000
Ashland MGP Site - Sediments
Manufactured Gas Plant (MGP) Site [Abstract]
Estimated cost of remediating site, low end of range	63,000,000
Estimated cost of remediating site, high end of range	77,000,000
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)	50.00%
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)	30.00%
Other MGP Sites
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites	$ 3,900,000	$ 2,500,000
Number of identified MGP sites under current investigation and/or remediation	2

XML

Summarized Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 240,388	$ 231,060	$ 210,175	$ 241,415	$ 217,395	$ 226,475	$ 194,173	$ 223,799	$ 923,038	$ 861,842	$ 875,790
Operating income	16,545	40,769	22,466	37,401	15,869	40,735	14,348	28,914	117,181	99,866	107,508
Net income	$ 7,225	$ 22,013	$ 10,544	$ 19,685	$ 7,131	$ 22,200	$ 5,742	$ 14,878	$ 59,468	$ 49,951	$ 51,006

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Comprehensive income:
Net income	$ 59,468	$ 49,951	$ 51,006
Derivative instruments:
Reclassification of losses to net income, net of tax of $51, $51 and $51, respectively.	76	77	76
Other comprehensive income	76	77	76
Comprehensive income	$ 59,544	$ 50,028	$ 51,082

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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.

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.

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 required to be decommissioned early by a regulator 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, 3.5 and 3.6 percent for the years ended Dec. 31, 2013, 2012 and 2011, 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 financing 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.

AROs — 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 effective 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.

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.

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.

RECs — 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. 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 remediation 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.

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, 2013 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical)	12 Months Ended
	Dec. 31, 2013
First Mortgage Bonds [Member] | Series Due Oct. 1, 2018 [Member]
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	5.25%
Debt instrument, maturity date	Oct. 01, 2018
First Mortgage Bonds [Member] | Series Due Sept. 1, 2038 [Member]
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	6.375%
Debt instrument, maturity date	Sep. 01, 2038
First Mortgage Bonds [Member] | Series Due Oct. 1, 2042
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	3.70%
Debt instrument, maturity date	Oct. 01, 2042
City of La Crosse Resource Recovery Bond [Member] | Series Due Nov. 1, 2021 [Member]
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	6.00%
Debt instrument, maturity date	Nov. 01, 2021
Fort McCoy System Acquisition [Member] | Due Oct. 15, 2030 [Member]
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	7.00%
Debt instrument, maturity date	Oct. 15, 2030

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

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.

The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	4,376	$	117,684	$	2,521	$	109,162
Pension and retiree medical obligations (a)	7	Various	8,202		85,220		7,328		104,426
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		12,679		—		10,458
Losses on reacquired debt	4	Term of related debt	801		5,737		800		6,538
State commission adjustments	1	Plant lives	410		9,355		339		7,533
Conservation programs	1	Less than one year	404		—		691		—
Deferred income tax adjustment	1, 6	Typically plant lives	—		1,763		—		1,974
Recoverable purchased natural gas and electric energy costs		Less than one year	673		—		358		—
Other		Various	—		755		11		368
Total regulatory assets			$	14,866	$	233,193	$	12,048	$	240,459

^(a)  Includes the non-qualified pension plan.

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	116,293	$	—	$	113,949
DOE settlement	11	Less than one year	6,814		—		5,628		—
Investment tax credit deferrals	1, 6	Various	—		9,976		—		9,626
Conservation programs	1	Less than one year	1,187		—		73		—
Deferred electric production and natural gas costs	1	Less than one year	1,542		—		134		—
Other		Various	174		155		251		171
Total regulatory liabilities			$	9,717	$	126,424	$	6,086	$	123,746

At Dec. 31, 2013 and 2012, approximately $0.1 million and $0.4 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes recoverable purchased natural gas and electric energy costs.

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Other Income, Net

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

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

(Thousands of Dollars)	2013			2012			2011
Interest income	$	538		$	736		$	324
Other nonoperating income	152			129			67
Insurance policy expense	(427		)	(389		)	(283		)
Other nonoperating expense	(10		)	—			(10		)
Other income, net	$	253		$	476		$	98

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Regulatory Assets and Liabilities, Regulatory Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 14,866,000		$ 12,048,000
Regulatory Asset, Noncurrent	233,193,000		240,459,000
Past expenditures not currently earning a return	100,000		400,000
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current	4,376,000		2,521,000
Regulatory Asset, Noncurrent	117,684,000		109,162,000
Regulatory asset, remaining amortization period	Various
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current	8,202,000	[1]	7,328,000	[1]
Regulatory Asset, Noncurrent	85,220,000	[1]	104,426,000	[1]
Regulatory asset, remaining amortization period	Various
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current	0		0
Regulatory Asset, Noncurrent	12,679,000		10,458,000
Regulatory asset, remaining amortization period	Plant lives
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current	801,000		800,000
Regulatory Asset, Noncurrent	5,737,000		6,538,000
Regulatory asset, remaining amortization period	Term of related debt
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	410,000		339,000
Regulatory Asset, Noncurrent	9,355,000		7,533,000
Regulatory asset, remaining amortization period	Plant lives
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	404,000		691,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period	Less than one year
Deferred Income Tax Adjustment
Regulatory Assets [Line Items]
Regulatory Asset, Current	0		0
Regulatory Asset, Noncurrent	1,763,000		1,974,000
Regulatory asset, remaining amortization period	Typically plant lives
Recoverable Purchased Natural Gas And Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current	673,000		358,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period	Less than one year
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Asset, Current	0		11,000
Regulatory Asset, Noncurrent	$ 755,000		$ 368,000
Regulatory asset, remaining amortization period	Various

[1] Includes the non-qualified pension plan.

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2013
Borrowing limit	$	150
Amount outstanding at period end	68
Average amount outstanding	41
Maximum amount outstanding	71
Weighted average interest rate, computed on a daily basis	0.30		%
Weighted average interest rate at period end	0.27

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	68			39			66
Average amount outstanding	20			61			24
Maximum amount outstanding	71			116			70
Weighted average interest rate, computed on a daily basis	0.31		%	0.39		%	0.37		%
Weighted average interest rate at period end	0.27			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, 2013 and 2012, 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.

NSP-Wisconsin has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $150 million and the credit facility terminates in July 2017.

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

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

• The credit facility has a financial covenant requiring that the 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 47 percent at Dec. 31, 2013. 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.

• The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.

• The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

At Dec. 31, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	68.0	$	82.0

^(a)  Credit facility expires in July 2017.

^(b)  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, 2013 and 2012.

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, 2013			Dec. 31, 2012
Notes payable to affiliates	$	0.5		$	0.6
Weighted average interest rate	0.24		%	0.33		%

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. 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 $100.0 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 $150.0 million due in 2018.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $3.5 million and $3.6 million, net of amortization, at Dec. 31, 2013 and 2012, respectively.  NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

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 $31.2 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements.  NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 52.8 percent at Dec. 31, 2013 and $17.1 million in retained earnings was not restricted.

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Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 1.3	$ 1.2	$ 1.1

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Adopted

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 No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Wisconsin implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 9 for the required disclosures.

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 regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  NSP-Wisconsin implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 13 for the required disclosures.

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2013

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Accounts receivable, net (a)
Accounts receivable	$	64,180		$	55,039
Less allowance for bad debts	(4,911		)	(4,333		)
	$	59,269		$	50,706

^(a)  Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	6,437	$	6,172
Fuel	5,915		6,664
Natural gas	9,123		6,849
	$	21,475	$	19,685

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	1,913,354		$	1,795,239
Natural gas plant	236,047			224,625
Common and other property	112,886			111,319
CWIP	127,954			62,629
Total property, plant and equipment	2,390,241			2,193,812
Less accumulated depreciation	(947,462		)	(895,576		)
	$	1,442,779		$	1,298,236

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Joint Ownership of Transmission Facilities

12 Months Ended

Dec. 31, 2013

Joint Ownership of Transmission Facilities [Abstract]

Joint Ownership of Transmission Facilities

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, 2013:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	13,337	$	4,659	$	30,199	77.9	%
La Crosse, Wis. to Madison, Wis.	—		—		5,431		50.0
Total NSP-Wisconsin	$	13,337	$	4,659	$	35,630

NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.

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Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities	$ (45,708,000)	$ (63,643,000)
Postretirement Benefit Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	19,432,000	22,127,000
Service cost	25,000	20,000	17,000
Interest cost	760,000	1,075,000	1,144,000
Medicare subsidy reimbursements	31,000	189,000
Plan amendments	0	(3,440,000)
Plan participants' contributions	621,000	893,000
Actuarial (gain) loss	(1,724,000)	1,486,000
Benefit payments	(1,992,000)	(2,918,000)
Obligation at Dec. 31	17,153,000	19,432,000	22,127,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	647,000	746,000
Actual return (loss) on plan assets	(13,000)	3,000
Plan participants' contributions	621,000	893,000
Employer contributions	1,483,000	1,923,000
Benefit payments	(1,992,000)	(2,918,000)
Fair value of plan assets at Dec. 31	746,000	647,000	746,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(16,407,000)	(18,785,000)
Current liabilities	(718,000)	(943,000)
Noncurrent liabilities	(15,689,000)	(17,842,000)
Net postretirement amounts recognized on consolidated balance sheets	(16,407,000)	(18,785,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	11,098,000	13,730,000
Prior service (credit) cost	(3,187,000)	(3,538,000)
Transition obligation	0	1,000
Total	7,911,000	10,193,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets	570,000	433,000
Noncurrent regulatory assets	7,341,000	9,760,000
Total	7,911,000	10,193,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date	12/31/2013	12/31/2012
Discount rate for year-end valuation (in hundredths)	4.82%	4.10%
Mortality table	RP 2000	RP 2000
Health care costs trend rate - initial (in hundredths)	7.00%	7.50%
Ultimate health care trend assumption rate (in hundredths)	4.50%	4.50%
Period until ultimate trend rate is reached (in years)	5 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO	1,773,000
One-percent decrease in APBO	(1,486,000)
One-percent increase in service and interest components	78,000
One-percent decrease in service and interest components	(61,000)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	1,500,000	1,900,000	2,400,000
Expected contribution to postretirement health care plans during 2014	1,500,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	25,000	20,000	17,000
Interest cost	760,000	1,075,000	1,144,000
Expected return on plan assets	(42,000)	(50,000)	(74,000)
Amortization of transition obligation	1,000	171,000	171,000
Amortization of prior service cost (credit)	(351,000)	(14,000)	(14,000)
Amortization of net loss	963,000	486,000	366,000
Net periodic benefit cost	1,356,000	1,688,000	1,610,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (in hundredths)	4.10%	5.00%	5.50%
Expected average long-term rate of return on assets (in hundredths)	7.11%	6.75%	7.50%
Xcel Energy Inc. | Postretirement Benefit Plan
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	17,600,000	47,100,000	49,000,000
Expected contribution to postretirement health care plans during 2014	$ 13,300,000

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 9,717	$ 6,086
Regulatory Liability, Noncurrent	126,424	123,746
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	116,293	113,949
Regulatory liability, remaining amortization period	Plant lives
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	6,814	5,628
Regulatory Liability, Noncurrent	0	0
Regulatory liability, remaining amortization period	Less than one year
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	9,976	9,626
Regulatory liability, remaining amortization period	Various
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	1,187	73
Regulatory Liability, Noncurrent	0	0
Regulatory liability, remaining amortization period	Less than one year
Deferred Electric Production And Natural Gas Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	1,542	134
Regulatory Liability, Noncurrent	0	0
Regulatory liability, remaining amortization period	Less than one year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	174	251
Regulatory Liability, Noncurrent	$ 155	$ 171
Regulatory liability, remaining amortization period	Various

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Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Employer	Dec. 31, 2012	Dec. 31, 2011
Multiemployer Plans [Abstract]
Number of employers that must be exceeded during a given period in order for certain union workers to participate in multiemployer plans	1
Multiemployer contributions	$ 130	$ 163	$ 169
Multiemployer Pension Plans
Multiemployer Plans [Abstract]
Multiemployer contributions	$ 130	$ 163	$ 169

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Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	$ 746		$ 647	$ 746
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	55		62	51
Net realized gains (losses)	0		(1)	(3)
Net unrealized gains (losses)	0		9	4
Purchases, issuances and settlements, net	0		(15)	10
Transfers in (out) of Level 3	(55)	[1]	0	0
Fair value of plan assets at Dec. 31	0		55	62
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	5		1
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	1		14	6
Net realized gains (losses)	0		0	0
Net unrealized gains (losses)	0		3	(2)
Purchases, issuances and settlements, net	0		(16)	10
Transfers in (out) of Level 3	(1)	[1]	0	0
Fair value of plan assets at Dec. 31	0		1	14
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	37		54
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	54		48	45
Net realized gains (losses)	0		(1)	(3)
Net unrealized gains (losses)	0		6	6
Purchases, issuances and settlements, net	0		1	0
Transfers in (out) of Level 3	(54)	[1]	0	0
Fair value of plan assets at Dec. 31	$ 0		$ 54	$ 48

[1] Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2013

Benefit Plans and Other Postretirement Benefits [Abstract]

Projected Benefit Payments for the Pension and Postretirement Benefit Plans

The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	ProjectedPension BenefitPayments		Gross Projected Postretirement Health Care BenefitPayments		ExpectedMedicare Part DSubsidies		Net Projected Postretirement Health Care BenefitPayments
2014	$	21,677	$	1,491	$	27	$	1,464
2015	14,257		1,459		25		1,434
2016	13,420		1,444		24		1,420
2017	13,851		1,384		20		1,364
2018	12,983		1,357		18		1,339
2019-2023	64,935		6,229		82		6,147

Contributions to Multiemployer Plans

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2013, 2012 and 2011.  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)	2013		2012		2011
Multiemployer plan contributions:
Pension	$	130	$	163	$	169
Total	$	130	$	163	$	169

Pension Plans

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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

	2013		2012
Domestic and international equity securities	31	%	29	%
Long-duration fixed income and interest rate swap securities	29		30
Short-to-intermediate term fixed income securities	16		12
Alternative investments	22		27
Cash	2		2
Total	100	%	100	%

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, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	4,332	$	—	$	—	$	4,332
Derivatives	—		937		—		937
Government securities	—		6,711		—		6,711
Corporate bonds	—		24,955		—		24,955
Asset-backed securities	—		307		—		307
Mortgage-backed securities	—		684		—		684
Common stock	4,533		—		—		4,533
Private equity investments	—		—		7,502		7,502
Commingled funds	—		84,364		—		84,364
Real estate	—		—		2,299		2,299
Securities lending collateral obligation and other	—		311		—		311
Total	$	8,865	$	118,269	$	9,801	$	136,935

	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

Changes in Level 3 Plan Assets

The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	749	$	—		$	—		$	—		$	(749	)	$	—
Mortgage-backed securities	2,128		—			—			—			(2,128		)	—
Private equity investments	8,545		1,083			(1,960		)	(166		)	—			7,502
Real estate	3,472		(129		)	247			450			(1,741		)	2,299
Total	$	14,894	$	954		$	(1,713	)	$	284		$	(4,618	)	$	9,801

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		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

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		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

Change in Projected Benefit Obligation

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)	2013			2012
Accumulated Benefit Obligation at Dec. 31	$	153,894		$	169,939
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	179,995		$	159,766
Service cost	5,682			4,568
Interest cost	6,924			7,765
Plan amendments	(1,109		)	216
Actuarial (gain) loss	(11,097		)	21,083
Benefit payments	(16,465		)	(13,403		)
Obligation at Dec. 31	$	163,930		$	179,995

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	136,546		$	121,348
Actual return on plan assets	5,525			16,079
Employer contributions	11,329			12,522
Benefit payments	(16,465		)	(13,403		)
Fair value of plan assets at Dec. 31	$	136,935		$	136,546

Funded Status of Plans

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(26,995	)	$	(43,449	)

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

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	84,773	$	99,338
Prior service cost	778		2,290
Total	$	85,551	$	101,628

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	7,631	$	6,895
Noncurrent regulatory assets	77,920		94,733
Total	$	85,551	$	101,628

Schedule of Assumptions Used

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.00	%	5.00	%	5.50	%
Expected average long-term increase in compensation level	3.75		4.00		4.00
Expected average long-term rate of return on assets	7.25		7.50		8.00

Measurement date Dec. 31, 2013 Dec. 31, 2012

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2000		RP 2000

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	5,682		$	4,568		$	4,271
Interest cost	6,924			7,765			8,031
Expected return on plan assets	(9,995		)	(10,489		)	(11,484		)
Amortization of prior service cost	417			1,771			1,895
Amortization of net loss	7,924			6,004			4,070
Net periodic pension cost	$	10,952		$	9,619		$	6,783

Postretirement Benefit Plan

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	31	$	—		$	—	$	31
Derivatives	—		(2		)	—		(2		)
Government securities	—		89			—		89
Insurance contracts	—		80			—		80
Corporate bonds	—		79			—		79
Asset-backed securities	—		5			—		5
Mortgage-backed securities	—		37			—		37
Commingled funds	—		452			—		452
Other	—		(25		)	—		(25		)
Total	$	31	$	715		$	—	$	746

	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

Changes in Level 3 Plan Assets

The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	1	$	—	$	—	$	—	$	(1	)	$	—
Mortgage-backed securities	54		—		—		—		(54		)	—
Total	$	55	$	—	$	—	$	—	$	(55	)	$	—

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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

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

Change in Projected Benefit Obligation

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)	2013			2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	19,432		$	22,127
Service cost	25			20
Interest cost	760			1,075
Medicare subsidy reimbursements	31			189
Plan amendments	—			(3,440		)
Plan participants’ contributions	621			893
Actuarial (gain) loss	(1,724		)	1,486
Benefit payments	(1,992		)	(2,918		)
Obligation at Dec. 31	$	17,153		$	19,432

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	647		$	746
Actual return on plan assets	(13		)	3
Plan participants’ contributions	621			893
Employer contributions	1,483			1,923
Benefit payments	(1,992		)	(2,918		)
Fair value of plan assets at Dec. 31	$	746		$	647

Funded Status of Plans

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status	$	(16,407	)	$	(18,785	)
Current liabilities	(718		)	(943		)
Noncurrent liabilities	(15,689		)	(17,842		)
Net postretirement amounts recognized on consolidated balance sheets	$	(16,407	)	$	(18,785	)

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	11,098		$	13,730
Prior service credit	(3,187		)	(3,538		)
Transition obligation	—			1
Total	$	7,911		$	10,193

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	570	$	433
Noncurrent regulatory assets	7,341		9,760
Total	$	7,911	$	10,193

Schedule of Assumptions Used

Measurement date Dec. 31, 2013 Dec. 31, 2012

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.82	%	4.10	%
Mortality table	RP 2000		RP 2000
Health care costs trend rate — initial	7.00	%	7.50	%

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.10	%	5.00	%	5.50	%
Expected average long-term rate of return on assets	7.11		6.75		7.50

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	25		$	20		$	17
Interest cost	760			1,075			1,144
Expected return on plan assets	(42		)	(50		)	(74		)
Amortization of transition obligation	1			171			171
Amortization of prior service credit	(351		)	(14		)	(14		)
Amortization of net loss	963			486			366
Net periodic postretirement benefit cost	$	1,356		$	1,688		$	1,610

Effects of One-Percent Change in Assumed Health Care Cost Trend Rate

A one-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	$	1,773	$	(1,486	)
Service and interest components	78		(61		)

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (USD $) In Millions, unless otherwise specified			1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2012 Bonds [Member] Series Due Oct. 1, 2042	Dec. 31, 2013 Bonds [Member] Series Due Oct. 1, 2042
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 100.0
Debt Instrument, Interest Rate, Stated Percentage			3.70%	3.70%
Debt Instrument, Maturity Date			Oct. 01, 2042	Oct. 01, 2042
Long-term Debt, Maturities, Repayments of Principal in Year Five	150.0
Deferred Finance Costs, Noncurrent, Net	3.5	3.6
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	31.2
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%
Calendar year average equity to total capitalization ratio	52.80%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 17.1

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Rate Matters (Notes)

12 Months Ended

Dec. 31, 2013

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

Wisconsin 2014 Electric and Gas Rate Case—In May 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent. The electric rate increase included a $4.5 million adjustment related to proceeds from a nuclear settlement agreement with the DOE.

The rate filing was based on a 2014 forecast test year, an ROE of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.

In October 2013, NSP-Wisconsin filed rebuttal testimony revising the requested electric rate increase to $34.3 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments.

In December 2013, the PSCW approved an electric rate increase of approximately $19.5 million or 3.1 percent based on a 10.2 percent ROE and an equity ratio of 52.5 percent. The PSCW also approved cost deferrals of $4.1 million for interchange agreement amounts from NSP-Minnesota related to the Monticello EPU project until the MPUC completes its prudence review. The PSCW did not change rates for NSP-Wisconsin’s natural gas utility. New electric rates went into effect on Jan. 1, 2014.

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

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.

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)	2013		2012		2011
Operating revenues:
Electric	$	136,917	$	125,344	$	124,334
Operating expenses:
Purchased power	416,173		405,016		399,649
Transmission expense	42,460		44,942		40,870
Natural gas purchased for resale	97		116		98
Other operating expenses — paid to Xcel Energy Services Inc.	61,531		54,137		54,885
Interest expense	22		22		48

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

	2013				2012
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	18,584	$	—	$	26,632
PSCo	—		8		—		71
SPS	26		—		—		4
Other subsidiaries of Xcel Energy Inc.	1,569		6,394		586		4,849
	$	1,595	$	24,986	$	586	$	31,556

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Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Line of Credit Facility [Line Items]
Credit agreement term (in years)	5
Line of Credit Facility, Maximum Borrowing Capacity	$ 150,000,000	[1]
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1 year
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed	65.00%
Line Of Credit Facility Debt To Total Capitalization Ratio	47.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions	15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions	75,000,000
Credit Facilities Drawn	68,000,000	[2]
Line of Credit Facility, Remaining Borrowing Capacity	82,000,000
Line of Credit Facility, Amount Outstanding	$ 0		$ 0
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.875%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.75%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.075%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.275%

[1] Credit facility expires in July 2017.

[2] Includes outstanding commercial paper.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

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)	2013		2012		2011
Operating revenues:
Electric	$	136,917	$	125,344	$	124,334
Operating expenses:
Purchased power	416,173		405,016		399,649
Transmission expense	42,460		44,942		40,870
Natural gas purchased for resale	97		116		98
Other operating expenses — paid to Xcel Energy Services Inc.	61,531		54,137		54,885
Interest expense	22		22		48

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

	2013				2012
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	18,584	$	—	$	26,632
PSCo	—		8		—		71
SPS	26		—		—		4
Other subsidiaries of Xcel Energy Inc.	1,569		6,394		586		4,849
	$	1,595	$	24,986	$	586	$	31,556

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments:
Reclassification of losses to net income, net of tax	$ (51)	$ (51)	$ (51)

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Schedule II, Valuation and Qualifying Accounts (Details) (Allowance for Bad Debts, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for Bad Debts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1	$ 4,333		$ 4,766		$ 4,262
Charged to costs and expenses	3,988		3,329		3,842
Charged to other accounts	1,199	[1]	1,310	[1]	1,241	[1]
Deductions from reserves	4,609	[2]	5,072	[2]	4,579	[2]
Balance at Dec. 31	$ 4,911		$ 4,333		$ 4,766

[1] Recovery of amounts previously written off.

[2] Principally bad debts written off.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Long-Term Debt
Unamortized discount	$ (2,321)		$ (2,457)
Total long-term debt, including current maturities	468,597		468,563
Less: current maturities	107		1,246
Total long-term debt	468,490		467,317
Common Stockholders' Equity
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2013 and 2012, respectively	93,300		93,300
Additional paid in capital	248,844		189,867
Retained earnings	262,499		234,376
Accumulated other comprehensive loss	(361)		(437)
Total common stockholder’s equity	604,282		517,106
First Mortgage Bonds [Member] | Series Due Oct. 1, 2018 [Member]
Long-Term Debt
Long-term debt, gross	150,000		150,000
First Mortgage Bonds [Member] | Series Due Sept. 1, 2038 [Member]
Long-Term Debt
Long-term debt, gross	200,000		200,000
First Mortgage Bonds [Member] | Series Due Oct. 1, 2042
Long-Term Debt
Long-term debt, gross	100,000		100,000
City of La Crosse Resource Recovery Bond [Member] | Series Due Nov. 1, 2021 [Member]
Long-Term Debt
Long-term debt, gross	18,600	[1]	18,600	[1]
Fort McCoy System Acquisition [Member] | Due Oct. 15, 2030 [Member]
Long-Term Debt
Long-term debt, gross	558		591
Other
Long-Term Debt
Long-term debt, gross	$ 1,760		$ 1,829

[1] Resource recovery financing

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Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) (Pension Plans, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	$ 136,935		$ 136,546	$ 121,348
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	14,894		15,807	17,801
Net realized gains (losses)	954		1,236	352
Net unrealized gains (losses)	(1,713)		(1,254)	1,230
Purchases, issuances and settlements, net	284		(895)	(3,576)
Transfers in (out) of Level 3	(4,618)	[1]	0	0
Fair value of plan assets at Dec. 31	9,801		14,894	15,807
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	307		749
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	749		1,578	1,367
Net realized gains (losses)	0		197	121
Net unrealized gains (losses)	0		(273)	(125)
Purchases, issuances and settlements, net	0		(753)	215
Transfers in (out) of Level 3	(749)	[1]	0	0
Fair value of plan assets at Dec. 31	0		749	1,578
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	684		2,128
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	2,128		3,781	5,984
Net realized gains (losses)	0		93	55
Net unrealized gains (losses)	0		(112)	(295)
Purchases, issuances and settlements, net	0		(1,634)	(1,963)
Transfers in (out) of Level 3	(2,128)	[1]	0	0
Fair value of plan assets at Dec. 31	0		2,128	3,781
Private equity investments
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	7,502		8,545
Private equity investments | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	8,545		8,440	6,704
Net realized gains (losses)	1,083		945	210
Net unrealized gains (losses)	(1,960)		(1,197)	648
Purchases, issuances and settlements, net	(166)		357	878
Transfers in (out) of Level 3	0	[1]	0	0
Fair value of plan assets at Dec. 31	7,502		8,545	8,440
Real estate
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Dec. 31	2,299		3,472
Real estate | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	3,472		2,008	3,746
Net realized gains (losses)	(129)		1	(34)
Net unrealized gains (losses)	247		328	1,002
Purchases, issuances and settlements, net	450		1,135	(2,706)
Transfers in (out) of Level 3	(1,741)	[1]	0	0
Fair value of plan assets at Dec. 31	$ 2,299		$ 3,472	$ 2,008

[1] Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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Commitments and Contingencies, Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 3,036	[1],[2]	$ 424	[1]
Liabilities recognized	0		1,962
Liabilities settled	0		0
Accretion	84		17
Revisions to prior estimates	(267)		633
Ending balance	2,853	[1],[2]	3,036	[1],[2]
Electric Plant Steam Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,962	[2]	0
Liabilities recognized	0		1,962
Accretion	43		0
Revisions to prior estimates	0		0
Ending balance	2,005	[2]	1,962	[2]
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	125	[2]	120
Liabilities recognized	0		0
Accretion	12		5
Revisions to prior estimates	224		0
Ending balance	361	[2]	125	[2]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	13	[2]	13
Liabilities recognized	0		0
Accretion	1		0
Revisions to prior estimates	22		0
Ending balance	36	[2]	13	[2]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	826	[2]	186
Liabilities recognized	0		0
Accretion	20		7
Revisions to prior estimates	(557)		633
Ending balance	289	[2]	826	[2]
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	75	[2]	71
Liabilities recognized	0		0
Accretion	5		4
Revisions to prior estimates	(5)		0
Ending balance	75	[2]	75	[2]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	35	[2]	34
Liabilities recognized	0		0
Accretion	3		1
Revisions to prior estimates	49		0
Ending balance	$ 87	[2]	$ 35	[2]

[1] Included in the other long-term liabilities balance in the consolidated balance sheets.

[2] There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.

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Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$ (437)	$ (514)	$ (590)
After-tax net realized losses on derivative transactions reclassified into earnings	76	77	76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (361)	$ (437)	$ (514)

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2013, 2012 AND 2011

(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:
2013	$	4,333	$	3,988	$	1,199	$	4,609	$	4,911
2012	4,766		3,329		1,310		5,072		4,333
2011	4,262		3,842		1,241		4,579		4,766

^(a)  Recovery of amounts previously written off.

^(b)  Principally bad debts written off.

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Commitments and Contingencies, Capital Commitments (Details)	12 Months Ended
	Dec. 31, 2013 Project
Capital Commitments [Abstract]
Number of major projects with capital commitments	1
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs	2.00%
Capital Commitments [Member] | CapX2020 [Member]
Capital Commitments [Abstract]
Number of transmission lines in Group 1 project	4

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	4,376	$	117,684	$	2,521	$	109,162
Pension and retiree medical obligations (a)	7	Various	8,202		85,220		7,328		104,426
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		12,679		—		10,458
Losses on reacquired debt	4	Term of related debt	801		5,737		800		6,538
State commission adjustments	1	Plant lives	410		9,355		339		7,533
Conservation programs	1	Less than one year	404		—		691		—
Deferred income tax adjustment	1, 6	Typically plant lives	—		1,763		—		1,974
Recoverable purchased natural gas and electric energy costs		Less than one year	673		—		358		—
Other		Various	—		755		11		368
Total regulatory assets			$	14,866	$	233,193	$	12,048	$	240,459

^(a)  Includes the non-qualified pension plan.

Regulatory Liabilities

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	116,293	$	—	$	113,949
DOE settlement	11	Less than one year	6,814		—		5,628		—
Investment tax credit deferrals	1, 6	Various	—		9,976		—		9,626
Conservation programs	1	Less than one year	1,187		—		73		—
Deferred electric production and natural gas costs	1	Less than one year	1,542		—		134		—
Other		Various	174		155		251		171
Total regulatory liabilities			$	9,717	$	126,424	$	6,086	$	123,746

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

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 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, for trading purposes and 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, 2013, 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 interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale.

The following table details the gross notional amounts of commodity options at Dec. 31, 2013 and 2012:

(Amounts in Thousands)(a)(b)	Dec. 31, 2013	Dec. 31, 2012
MMBtu of natural gas	987	53

^(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 derivatives 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)	2013			2012			2011
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(437	)	$	(514	)	$	(590	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			77			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(361	)	$	(437	)	$	(514	)

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, 2013, 2012 and 2011.

During the year ended Dec. 31, 2013, 2012 and 2011, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million, $0.4 million and $3.6 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 and option premium amortization totaling $0.7 million, $2.9 million and $2.9 million were recognized for each of the years ended Dec. 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting(a)		Total(b)
Current derivative assets
Natural gas commodity	$	—	$	580	$	—	$	580	$	—	$	580

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

^(a)  NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013 and 2012.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

^(b)  Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.

^(c)  Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2013				2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	468,597	$	518,269	$	468,563	$	576,353

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, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.