10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2015

or

¨ 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. ¨ Yes x No

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller Reporting Company ¨
(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).  ¨ Yes x No

As of Feb. 22, 2016, 933,000 shares of common stock, par value $100 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2016 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2016. Such information set forth under such heading is incorporated herein by this reference hereto.

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	7
Fuel Sources	8
Renewable Energy Sources	9
Summary of Recent Federal Regulatory Developments	9
Electric Operating Statistics	11
NATURAL GAS UTILITY OPERATIONS	12
Public Utility Regulation	12
Capability and Demand	13
Natural Gas Supply and Costs	13
Natural Gas Operating Statistics	14
GENERAL	14
ENVIRONMENTAL MATTERS	15
EMPLOYEES	15
Item 1A — Risk Factors	15
Item 1B — Unresolved Staff Comments	24
Item 2 — Properties	25
Item 3 — Legal Proceedings	25
Item 4 — Mine Safety Disclosures	26
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6 — Selected Financial Data	26
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	29
Item 8 — Financial Statements and Supplementary Data	29
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A — Controls and Procedures	73
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	74
PART IV
Item 15 — Exhibits, Financial Statement Schedules	74
SIGNATURES	78

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
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
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
Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
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
C&I	Commercial and Industrial
CAA	Clean Air Act
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
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
ITC	Investment tax credit
LNG	Liquefied natural gas

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MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
NAAQS	National Ambient Air Quality Standard
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NOL	Net operating loss
NOx	Nitrogen oxide
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PI	Prairie Island nuclear generating plant
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
REC	Renewable energy credit
ROE	Return on equity
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
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 256,000 customers and natural gas utility service to approximately 112,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2015.  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 and sand mining for oil and gas extraction.  For small commercial and industrial customers, significant electric retail sales include the following industries:  grocery and dining establishments, educational services and health services.  Generally, NSP-Wisconsin’s earnings contribute approximately five 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: improving utility performance; driving operational excellence; improving customer experience; and investing for the future.

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.

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.

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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. 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 2016, assuming normal weather conditions, is as follows:

	System Peak Demand (in MW)
	2013	2014	2015	2016 Forecast
NSP System	9,524	8,848	8,621	9,327

The peak demand for the NSP System typically occurs in the summer. The 2015 system peak demand for the NSP System occurred on Aug. 14, 2015. The 2015 system peak demand was lower due to cooler summer weather. The 2016 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.  Generally, long-term dispatchable purchased power contracts typically require a periodic payment to secure the capacity and a charge for the delivered associated energy. Long-term energy-only purchased power contracts contain a charge for the purchased energy. 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 — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.

NSP System Resource Plans — In January 2015, NSP-Minnesota filed its 2016-2030 Integrated Resource Plan (the Plan) with the MPUC.

In October 2015, NSP-Minnesota proposed revisions to the Plan. The revised proposal addressed stakeholder recommendations as well as the final CPP issued by the EPA. The revised Plan is based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The provisions included in the Plan would allow for a 60 percent reduction in carbon emissions from 2005 levels by 2030 and is expected to result in 63 percent of NSP System energy being carbon-free by 2030. Specific terms of the proposal include:

• The addition of 800 MW of wind and 400 MW of utility scale solar to the pre-2020 time-frame;

• The addition of 1000 MW of wind and 1000 MW of utility scale solar between 2020-2030;

• The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;

• The addition of a 230 MW natural gas combustion turbine in North Dakota by 2025;

• Replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site no later than 2026; and

• Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030’s.

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NSP-Minnesota believes this will provide substantial opportunities for the ownership of renewable generation and replacement thermal generation. In January 2016, NSP-Minnesota filed supplemental economic and technical information in support of its revised Plan, demonstrating anticipated compliance with the CPP while maintaining reasonable costs for customers. Additionally, NSP-Minnesota responded to MPUC inquiries regarding forecasted cost increases at PI (through end of licensed life) and committed to provide additional information if the MPUC wishes to further explore alternatives to operating PI through its current licenses. While the procedural schedule has not yet been finalized, the current expectation is that the MPUC will make a decision in the second half of 2016.

CapX2020 — The estimated cost of the five major CapX2020 transmission projects is $2 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment.  As of Dec. 31, 2015, Xcel Energy has invested $1.0 billion of its $1.1 billion share of the five CapX2020 transmission projects.

The Wisconsin portion of the Hampton, Minnesota to La Crosse, Wisconsin 161/345 KV transmission line includes a new substation and approximately 50 miles of new 345 KV transmission line, at an estimated cost of $211 million. The final 161 KV segment of the project went into service in January 2016, while the final 345 KV segment of the project is expected to go into service in the fall of 2016.

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.  NSP-Wisconsin’s half of the line will be shared with three co-owners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.

In April 2015, the PSCW issued its order approving a CPCN and route for the project. In June 2015, the PSCW denied two requests for rehearing. Two groups have appealed the CPCN Order to county circuit court. Court action is pending and the CPCN remains in full effect unless one of the parties seeks and receives a stay from the court and posts a bond to cover damages the utilities may incur due to delay. The 180-mile project is expected to cost approximately $580 million. NSP-Wisconsin’s portion of the investment is estimated to be approximately $207 million. Construction on the line began in January 2016, with completion anticipated by late 2018.

2015 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the year ended Dec. 31, 2015 were lower than authorized in rates and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery rules, primarily due to lower load as a result of mild weather, lower natural gas prices and lower purchased power prices in the MISO market. Accordingly, NSP-Wisconsin recorded a deferral of approximately $9.2 million through Dec. 31, 2015. In the first quarter of 2016, NSP-Wisconsin will file a reconciliation of 2015 fuel costs with the PSCW. The amount of any potential refund is subject to review and approval by the PSCW, which is not expected until mid-2016.

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
2015	$	2.15	47	%	$	0.83	40	%	$	3.89	13	%	$	1.85
2014	2.23		52		0.89		42		6.27		6		1.94
2013	2.20		49		0.95		40		5.08		11		2.03

^(a)  Includes refuse-derived fuel and wood.

The cost of natural gas in 2015 decreased due to lower wholesale commodity prices.

See Items 1A and 7 for further discussion of fuel supply and costs.

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Fuel Sources

Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2015 and 2014 were approximately 67 and 27 days usage, respectively. At Dec. 31, 2015, milder weather, purchase commitments and resolution of railcar congestion resulted in coal inventories being above optimal levels. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana. During 2015 and 2014, coal requirements for the NSP System’s major coal-fired generating plants were approximately 8.3 million tons and 9.3 million tons, respectively. Coal requirements for 2015 were lower due to the retirement of Black Dog Units 3 and 4 and relatively low natural gas prices. The estimated coal requirements for 2016 are approximately 7.9 million tons.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 90 percent of their estimated coal requirements in 2016, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 90 percent of requirements for the first year, 60 percent of requirements in year two, and 30 percent of requirements in year three. 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 2016 and 2017. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Nuclear — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its’ nuclear plants. 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 59 percent of the requirements for 2019 through 2030;

• Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 54 percent of the requirements for 2022 through 2030; and

• Current enrichment service contracts cover 100 percent of the requirements through 2026 and approximately 34 percent of the requirements for 2027 through 2030.

Fabrication services for Monticello and PI are 100 percent committed through 2030 and 2019, respectively. 

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 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, transportation and storage services for power plants are procured under contracts 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 variable pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC approved transportation tariff rates. 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, 2015 and 2014, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $310 million and $349 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2016 to 2028.

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

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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, 2015, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 12.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.

• Renewable energy comprised 23.3 percent and 24.2 percent of the NSP System’s total energy for 2015 and 2014, respectively;

• Wind energy comprised 13.6 percent and 13.7 percent of the total energy for 2015 and 2014, respectively;

• Hydroelectric energy comprised 7.3 percent and 7.8 percent of the total energy for 2015 and 2014, respectively; and

• Biomass and solar power comprised approximately 2.4 percent and 2.7 percent of the total energy for 2015 and 2014, respectively.

The NSP System also offers customer-focused renewable energy initiatives. Windsource® allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources. In 2015, the number of customers utilizing Windsource increased to approximately 50,000 from 43,000 in 2014.

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 1,458 PV systems with approximately 18.3 MW of aggregate capacity and over 915 PV systems with approximately 11.1 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2015 and 2014, respectively.

Wind—The NSP System acquires the majority of its wind energy from PPAs with wind farm owners. Currently, the NSP System has more than 120 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW. The NSP System owns and operates four wind farms which have the capacity to generate 652 MWs.

• Collectively, the NSP System had approximately 2,210 and 1,860 MWs of wind energy on its system at the end of 2015 and 2014, respectively. 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 the existing contracts was approximately $42 and $41 for 2015 and 2014, respectively.  The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2015 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.

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 277.5 MW of capacity. For 2015, PPAs provided approximately 34 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 725 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

Wholesale and Commodity Marketing Operations

NSP-Wisconsin conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Wisconsin uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates. See Item 7 for further discussion.

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Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, 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, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In March, 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any litigated ROE complaint proceedings until at least mid-2016. See Note 10 to the consolidated financial statements for discussion of the MISO ROE Complaints.

NERC Critical Infrastructure Protection Requirements — The FERC has approved Version 5 of NERC’s critical infrastructure protection standards, which added additional requirements to strengthen grid security controls. Requirements must be applied by NSP-Wisconsin to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. NSP-Wisconsin is currently in the process of implementing initiatives to meet the compliance deadlines. The additional cost for compliance is anticipated to be recoverable through rates.

NERC Physical Security Requirements — In November 2014, the FERC approved NERC’s proposed critical infrastructure protection standard related to physical security for bulk electric system facilities. The new standard became enforceable in October 2015 with staggered milestone deliverable dates through 2016.  NSP-Wisconsin has performed an initial risk assessment and is in the process of developing physical security plans in accordance with the requirements of the standard. The additional cost for compliance is anticipated to be recoverable through rates.

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) —SPP and MISO have been engaged in a longstanding dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagree over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014. In June 2014, the FERC set the issues for settlement judge and hearing procedures.

In January 2016, FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provide a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period and $16 million annually prospectively, subject to a true-up. Separate settlement discussions regarding the MISO tariff change to recover SPP charges are ongoing. NSP-Minnesota and NSP-Wisconsin expect to be able to recover any resulting MISO charges in retail rates. In January 2016, SPP filed a proposal regarding distribution of the revenues to SPP members, including SPS. FERC approval is pending. The revenue allocated to SPS is not expected to be material.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2015			2014			2013
Electric sales (Millions of KWh)
Residential	1,863			1,984			1,990
Large commercial and industrial	1,868			1,823			1,698
Small commercial and industrial	2,877			2,902			2,837
Public authorities and other	39			42			36
Total retail	6,647			6,751			6,561
Sales for resale	—			—			1
Total energy sold	6,647			6,751			6,562
Number of customers at end of period
Residential	215,135			214,350			213,665
Large commercial and industrial	120			114			107
Small commercial and industrial	39,254			38,939			38,549
Public authorities and other	1,175			1,144			1,149
Total customers	255,684			254,547			253,470
Electric revenues (Thousands of Dollars)
Residential	$	244,417		$	254,277		$	247,081
Large commercial and industrial	141,007			136,435			125,151
Small commercial and industrial	284,427			282,016			267,796
Public authorities and other	6,576			6,636			6,184
Total retail	676,427			679,364			646,212
Interchange revenues from NSP-Minnesota	163,255			145,102			136,917
Other electric revenues	(4,684		)	5,282			6,039
Total electric revenues	$	834,998		$	829,748		$	789,168
KWh sales per retail customer	25,997			26,522			25,885
Revenue per retail customer	$	2,646		$	2,669		$	2,549
Residential revenue per KWh		13.12	¢		12.82	¢		12.42	¢
Large commercial and industrial revenue per KWh	7.55			7.48			7.37
Small commercial and industrial revenue per KWh	9.89			9.72			9.44
Total retail revenue per KWh	10.18			10.06			9.85

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Energy Source Statistics

	Year Ended Dec. 31
	2015			2014			2013
NSP System	Millions ofKWh	Percent of Generation		Millions ofKWh	Percent of Generation		Millions ofKWh	Percent of Generation
Coal	15,961	35	%	18,079	39	%	15,844	36	%
Nuclear	12,425	27		13,434	29		12,161	28
Natural Gas	6,689	15		3,402	7		5,550	13
Wind (a)	6,235	14		6,243	14		5,481	13
Hydroelectric	3,326	7		3,560	8		3,223	7
Other (b)	1,083	2		1,417	3		1,323	3
Total	45,719	100	%	46,135	100	%	43,582	100	%
Owned generation	33,818	74	%	33,641	73	%	29,249	67	%
Purchased generation	11,901	26		12,494	27		14,333	33
Total	45,719	100	%	46,135	100	%	43,582	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 eight, seven, and eight million net KWh for 2015, 2014, and 2013, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of NSP‑Wisconsin are uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2015, average annual sales to the typical NSP‑Wisconsin residential customer declined 18 percent, while sales to the typical small C&I customer increased 8 percent, each on a weather-normalized basis. The increase in C&I is due to new load growth. Although wholesale price increases do not directly affect earnings because of natural gas cost-recovery mechanisms, high prices can encourage further efficiency efforts by customers.

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires 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 PGA 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 158,719 MMBtu, which occurred on Jan. 7, 2015, and 163,520 MMBtu, which occurred on Jan. 6, 2014.

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 139,127 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 31 percent of winter natural gas requirements and 34 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 12 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 2015-2016 supply plan was approved by the PSCW in September 2015.

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:

2015	$	4.11
2014	6.52
2013	4.51

The cost of natural gas in 2015 decreased due to lower wholesale commodity prices.

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 2016 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, 2015, NSP-Wisconsin was committed to approximately $55 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 11 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

See Items 1A and 7 for further discussion of natural gas supply and costs.

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Natural Gas Operating Statistics

	Year Ended Dec. 31
	2015		2014		2013
Natural gas deliveries (Thousands of MMBtu)
Residential	6,584		8,098		7,505
Commercial and industrial	9,116		10,626		10,131
Total retail	15,700		18,724		17,636
Transportation and other	4,756		4,729		4,344
Total deliveries	20,456		23,453		21,980
Number of customers at end of period
Residential	99,316		98,325		96,974
Commercial and industrial	12,902		12,773		12,646
Total retail	112,218		111,098		109,620
Transportation and other	25		23		23
Total customers	112,243		111,121		109,643
Natural gas revenues (Thousands of Dollars)
Residential	$	61,277	$	82,851	$	67,745
Commercial and industrial	55,677		82,181		63,896
Total retail	116,954		165,032		131,641
Transportation and other	3,193		4,597		1,226
Total natural gas revenues	$	120,147	$	169,629	$	132,867
MMBtu sales per retail customer	139.91		168.54		160.88
Revenue per retail customer	$	1,042	$	1,485	$	1,201
Residential revenue per MMBtu	9.31		10.23		9.03
Commercial and industrial revenue per MMBtu	6.11		7.73		6.31
Transportation and other revenue per MMBtu	0.67		0.97		0.28

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 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 is a vertically integrated utility, subject to traditional cost-of-service regulation. 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 solar generation (typically rooftop solar or solar gardens) 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 can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of 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 certain 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 believes its rates and services are competitive with currently available alternatives. 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. 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 present and future environmental regulations to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. 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. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. We believe, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2015, NSP-Wisconsin had 560 full-time employees and three part-time employees, of which 400 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.

Oversight of Risk and Related Processes

A key accountability of the Board is the oversight of material risk, and our Board employs an effective process for doing so. As outlined below, management and each Board committee has responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board.

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 economies and the environment when identifying, assessing, managing and mitigating risk. 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.

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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. 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 to mitigate the risks inherent in the implementation strategy. 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 internal corporate areas such as internal audit, the corporate controller and legal services.

Management communicates regularly with the Board and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board. The presentation and the discussion of the key risks 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 Board approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of the Company. First, the Board as a whole regularly reviews management’s key risk assessment and analyzes areas of existing and future risks and opportunities. In addition, the Board assigns oversight of certain critical risks to each of its four standing committees to ensure these risks are well understood and given focused oversight by the committee with the most applicable expertise. The Audit Committee is responsible for reviewing the adequacy of risk oversight and affirming that appropriate oversight occurs. New risks are considered and assigned as appropriate during the annual Board and committee evaluation process, and committee charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board for consideration where deemed appropriate to ensure broad Board understanding of the nature of the risk. Finally, the Board conducts an annual strategy session where the Company’s future plans and initiatives are reviewed and confirmed.

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, shift generation to lower-emitting but potentially more costly facilities, 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 makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2015, 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.  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 may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂, CO₂ and other GHGs, particulates, cooling water intakes, water discharges and ash management.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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

Climate change can create physical and financial risk. Physical risks from climate change can include changes in weather conditions, changes in precipitation and extreme weather events.

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. 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 result in 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 may raise electricity prices, 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, whether caused by climate change or otherwise, 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.

Climate change may impact a region’s economic health, which could impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as regulation of CO₂ emissions under section 111(d) of the CAA, 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.

The profitability of our operations 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.  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, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and there is no assurance that regulators would allow full recovery of all remaining 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 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.

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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. As a result, we frequently need to access capital 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 could also have an adverse effect on our operating results.  Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. 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.

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 SPP, PJM and MISO, in which any credit losses are socialized to all market participants.

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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 most of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, 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 changed the minimum funding requirements for defined benefit pension plans with modifications 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 could 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 have increased 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.  Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Operational Risks

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products 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). Actual settlements can vary significantly from estimated fair values recorded, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously anticipated costs.  Therefore, a significant disruption could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments could have a negative impact on our cash flows and potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and 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 including rail shipments of coal, 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.

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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, PI 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 and the current lack of a long-term disposal solution for radioactive materials;

• Limitations on the amounts and types of insurance 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. For example, similar to pensions, interest rate and other assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.

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 and/or shut down a unit until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses. 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 or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.

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

Most electric utility investments are long-lived and are planned to be used for decades. Transmission and generation investments typically have long lead times, and therefore are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. The electric utility sector is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease carbon dioxide emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. These changes introduce additional uncertainty into long term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution.

The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. NSP-Wisconsin is engaged in significant and ongoing infrastructure investment programs to accommodate distributed generation and maintain high system reliability. NSP-Wisconsin is also investing in renewable and natural gas-fired generation to reduce our carbon dioxide emissions profile. Early plant retirements could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand, and increases in electric rates.

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.  We maintain insurance against some, but not all, of these risks and losses.

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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 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. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. 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, 2015, Xcel Energy Inc. and its utility subsidiaries had approximately $12.5 billion of long-term debt and $1.5 billion of short-term debt and current maturities.  Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2015, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $12.5 million and exposure of $0.1 million. Xcel Energy also had additional guarantees of $41.3 million at Dec. 31, 2015 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 2015, 2014 and 2013 we paid $53.9 million, $43.8 million and $31.0 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 Inc.'s cash needs.  This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Wisconsin is imposed by our 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.

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Public Policy Risks

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

The EPA is regulating GHGs from power plants with state plans to achieve the EPA’s goals due by September 2018. Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs. 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 additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International agreements could have an impact to the extent they lead to future federal or state regulations.

The United States continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change (UNFCCC). In December 2015, the 21^st Conference of the Parties to the UNFCCC reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2^o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5^o Celsius. The Paris Agreement could result in future additional GHG reductions in the United States.

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.

The form and stringency of GHG regulation in the power sector has become more clear with the finalization of the Clean Power Plan by the EPA. The legality of the Clean Power Plan is being challenged in the courts. In addition, uncertainties remain regarding implementation plans in our states (and the federal plan imposed by the EPA for states who do not submit approvable plans), including what opportunities are available to reduce costs, whether and what type of emission trading will be available, how states will allocate the reduction burden among utilities, what actions are creditable and the indirect impact of carbon regulation on natural gas and coal prices.

An important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO₂ and NOx, mercury, regional haze, ozone and particulate matter, water intakes, water discharges and ash management. The costs of investment to comply with these rules could be substantial and in some cases would lead to early retirement of coal units. 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 up to $1 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas.  In addition, NERC electric reliability standards and critical infrastructure protection requirements are 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. Some states have the authority to impose substantial penalties in the event of non-compliance.

We attempt to mitigate the risk of regulatory penalties 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.

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Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which is discussed 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.  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.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we 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.

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, the 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 an industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In addition, 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.

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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 affected by 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, such an event would likely receive regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of 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.

Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

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

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

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

Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2015 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., 4 Units	Natural Gas	1973	183
Hydro:
Various locations, 63 Units	Hydro	Various	135
		Total	524

^(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, 2015:

Conductor Miles
345 KV	1,152
161 KV	1,577
115 KV	1,810
Less than 115 KV	32,355

NSP-Wisconsin had 204 electric utility transmission and distribution substations at Dec. 31, 2015.

Natural gas utility mains at Dec. 31, 2015:

Miles
Distribution	2,342

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.

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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 2015 in excess of approximately $33.3 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 52.6 percent at Dec. 31, 2015 and $2.4 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 2015 and 2014 were as follows:

(Thousands of Dollars)	2015		2014
First quarter	$	13,315	$	8,057
Second quarter	11,993		16,243
Third quarter	13,664		11,486
Fourth quarter	15,321		14,957

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).

Financial Review

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

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein 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 expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 (including the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: : 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; cyber security threats and data security breaches; 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; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Results of Operations

NSP-Wisconsin’s net income was $74.6 million for 2015 compared with $70.6 million for 2014.  Higher electric revenues, primarily due to an electric rate increase and lower O&M expenses were partially offset by higher depreciation, lower natural gas margins, and the impact of the Monticello LCM/EPU project loss. See Note 10 to the consolidated financial statements for further discussion of the Monticello LCM/EPU project loss.

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)	2015			2014
Electric revenues	$	835		$	830
Electric fuel and purchased power	(430		)	(445		)
Electric margin	$	405		$	385

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)	2015 vs. 2014
Interchange agreement billings with NSP-Minnesota	$	12
Retail rate increase	4
Estimated impact of weather	(6		)
Retail sales growth, excluding weather impact	(4		)
Fuel and purchased power cost recovery	(2		)
Other, net	1
Total increase in electric revenues	$	5

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Electric Margin

(Millions of Dollars)	2015 vs. 2014
Interchange agreement billings with NSP-Minnesota	$	21
Fuel recovery	8
Retail rate increase	4
Estimated impact of weather	(6		)
Retail sales growth, excluding weather impact	(4		)
Other, net	(3		)
Total increase in electric margin	$	20

Natural Gas Revenues and Margin

Total natural gas expense 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 natural gas revenues and margin:

(Millions of Dollars)	2015			2014
Natural gas revenues	$	120		$	170
Cost of natural gas sold and transported	(71		)	(114		)
Natural gas margin	$	49		$	56

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)	2015 vs. 2014
Purchased natural gas adjustment clause recovery	$	(44	)
Estimated impact of weather	(5		)
Retail sales decline, excluding weather impact	(1		)
Total decrease in natural gas revenues	$	(50	)

Natural Gas Margin

(Millions of Dollars)	2015 vs. 2014
Estimated impact of weather	$	(5	)
Retail sales decline, excluding weather impact	(1		)
Other, net	(1		)
Total decrease in natural gas margin	$	(7	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased$11.8 million, or 6.2 percent, for 2015 compared with 2014.  The decrease was primarily due to Interchange Agreement billings with NSP-Minnesota related to timing of transmission projects.

(Millions of Dollars)	2015 vs. 2014
Interchange agreement billings with NSP-Minnesota	$	(12	)
Labor and contract labor	2
Other, net	(2		)
Total decrease in O&M expenses	$	(12	)

Depreciation and Amortization — Depreciation and amortization increased$11.6 million, or 14.6 percent, for 2015 compared with 2014. The increase was primarily attributable capital investments.

Interest Charges— Interest charges increased$3.5 million, or 11.8 percent, for 2015 compared with 2014. The increase was primarily due to higher long-term debt levels.

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Income Taxes — Income tax expense increased$1.8 million for 2015 compared with 2014.  The increase in income tax expense wasprimarily due to higher pretax earnings in 2015. The ETR was 37.2 percent for 2015, compared with 37.5 percent for 2014.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

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

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

Commodity Price Risk — NSP-Wisconsin is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into short- and long-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, 2015 and 2014, a 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact annual pretax interest expense by approximately $0.1 million and $0.8 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, 2015 and 2014, 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.

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Management Report on Internal Controls Over Financial Reporting

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

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

NSP-Wisconsin management assessed the effectiveness of NSP-Wisconsin’s internal control over financial reporting as of Dec. 31, 2015. 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 (2013). Based on our assessment, we believe that, as of Dec. 31, 2015, NSP-Wisconsin’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE	/s/ TERESA S. MADDEN
Ben Fowke	Teresa S. Madden
Chairman and Chief Executive Officer	Executive Vice President, Chief Financial Officer
Feb. 22, 2016	Feb. 22, 2016

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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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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 22, 2016

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2015			2014			2013
Operating revenues
Electric	$	834,998		$	829,748		$	789,168
Natural gas	120,147			169,629			132,867
Other	1,396			1,085			1,003
Total operating revenues	956,541			1,000,462			923,038
Operating expenses
Electric fuel and purchased power, non-affiliates	10,795			19,595			18,129
Purchased power, affiliates	419,028			425,471			416,173
Cost of natural gas sold and transported	70,988			114,250			81,572
Operating and maintenance expenses	179,413			191,213			175,522
Conservation program expenses	11,695			11,537			12,333
Depreciation and amortization	91,245			79,654			76,897
Taxes (other than income taxes)	28,181			27,114			25,231
Loss on Monticello life cycle management/extended power uprate project	5,237			—			—
Total operating expenses	816,582			868,834			805,857
Operating income	139,959			131,628			117,181
Other income, net	883			270			253
Allowance for funds used during construction — equity	7,253			7,060			4,259
Interest charges and financing costs
Interest charges — includes other financing costs of $1,738, $1,570, and $1,538, respectively	32,731			29,273			27,797
Allowance for funds used during construction — debt	(3,510		)	(3,360		)	(1,981		)
Total interest charges and financing costs	29,221			25,913			25,816
Income before income taxes	118,874			113,045			95,877
Income taxes	44,238			42,403			36,409
Net income	$	74,636		$	70,642		$	59,468

See Notes to Consolidated Financial Statements

32

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2015		2014		2013
Net income	$	74,636	$	70,642	$	59,468
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $51 for the years ended Dec. 31, 2015, 2014, and 2013, respectively.	76		76		76
Other comprehensive income	76		76		76
Comprehensive income	$	74,712	$	70,718	$	59,544

See Notes to Consolidated Financial Statements

33

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2015			2014			2013
Operating activities
Net income	$	74,636		$	70,642		$	59,468
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	92,656			80,875			78,048
Deferred income taxes	45,833			45,396			25,789
Amortization of investment tax credits	(528		)	(527		)	(664		)
Allowance for equity funds used during construction	(7,253		)	(7,060		)	(4,259		)
Loss on Monticello life cycle management/extended power uprate project	5,237			—			—
Provision for bad debts	3,947			4,431			3,988
Net derivative losses (gains)	482			10			(279		)
Changes in operating assets and liabilities:
Accounts receivable	71			(5,558		)	(12,702		)
Accrued unbilled revenues	5,869			(1,933		)	(2,496		)
Inventories	3,126			(3,210		)	(1,879		)
Other current assets	7,135			(3,501		)	(3,749		)
Accounts payable	(7,626		)	2,936			(1,811		)
Net regulatory assets and liabilities	(27,114		)	(34,697		)	(2,062		)
Other current liabilities	5,147			(911		)	7,589
Pension and other employee benefit obligations	(3,177		)	(6,134		)	(8,759		)
Change in other noncurrent assets	209			(113		)	232
Change in other noncurrent liabilities	716			2,534			1,119
Net cash provided by operating activities	199,366			143,180			137,573
Investing activities
Utility capital/construction expenditures	(251,797		)	(288,209		)	(201,278		)
Allowance for equity funds used during construction	7,253			7,060			4,259
Other, net	(224		)	(166		)	(421		)
Net cash used in investing activities	(244,768		)	(281,315		)	(197,440		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	(68,000		)	10,000			29,000
Proceeds from notes payable to affiliates	—			30			—
Repayments of notes payable to affiliates	—			—			(80		)
Proceeds from issuance of long-term debt	97,969			98,534			—
Repayments of long-term debt	(87		)	(107		)	(160		)
Capital contributions from parent	69,243			73,432			58,977
Dividends paid to parent	(53,929		)	(43,818		)	(30,980		)
Net cash provided by financing activities	45,196			138,071			56,757
Net change in cash and cash equivalents	(206		)	(64		)	(3,110		)
Cash and cash equivalents at beginning of period	1,285			1,349			4,459
Cash and cash equivalents at end of period	$	1,079		$	1,285		$	1,349
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(27,491	)	$	(24,442	)	$	(24,376	)
Cash received (paid) for income taxes, net	5,762			3,474			(9,842		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	16,729		$	35,267		$	27,222

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	1,079		$	1,285
Accounts receivable, net	56,378			60,396
Accrued unbilled revenues	47,698			53,567
Inventories	21,559			24,685
Regulatory assets	16,146			20,036
Prepaid taxes	25,976			28,628
Deferred income taxes	3,138			8,201
Prepayments and other	2,387			6,918
Total current assets	174,361			203,716
Property, plant and equipment, net	1,828,079			1,674,281
Other assets
Regulatory assets	289,196			280,693
Other investments	4,042			3,818
Other	5,211			4,612
Total other assets	298,449			289,123
Total assets	$	2,300,889		$	2,167,120
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,131		$	1,235
Short-term debt	10,000			78,000
Notes payable to affiliates	500			500
Accounts payable	34,317			61,530
Accounts payable to affiliates	24,538			26,524
Dividends payable to parent	15,322			14,957
Regulatory liabilities	11,781			16,940
Environmental liabilities	17,155			29,116
Accrued interest	7,945			7,658
Other	15,778			12,265
Total current liabilities	138,467			248,725
Deferred credits and other liabilities
Deferred income taxes	393,569			348,180
Deferred investment tax credits	8,560			9,089
Regulatory liabilities	141,289			132,674
Environmental liabilities	77,441			78,620
Customer advances	18,480			17,623
Pension and employee benefit obligations	49,889			51,313
Other	16,347			16,151
Total deferred credits and other liabilities	705,575			653,650
Commitments and contingencies
Capitalization
Long-term debt	666,462			567,056
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2015 and 2014, respectively	93,300			93,300
Additional paid in capital	394,553			322,276
Retained earnings	302,741			282,398
Accumulated other comprehensive loss	(209		)	(285		)
Total common stockholder’s equity	790,385			697,689
Total liabilities and equity	$	2,300,889		$	2,167,120

See Notes to Consolidated Financial Statements

35

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, 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
Net income						70,642						70,642
Other comprehensive income									76			76
Common dividends declared to parent						(50,743		)				(50,743		)
Contribution of capital by parent				73,432								73,432
Balance at Dec. 31, 2014	933,000	$	93,300	$	322,276	$	282,398		$	(285	)	$	697,689
Net income						74,636						74,636
Other comprehensive income									76			76
Common dividends declared to parent						(54,293		)				(54,293		)
Contribution of capital by parent				72,277								72,277
Balance at Dec. 31, 2015	933,000	$	93,300	$	394,553	$	302,741		$	(209	)	$	790,385

See Notes to Consolidated Financial Statements

36

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2015			2014
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
June 15, 2024, 3.3%	200,000			100,000
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%	490			523
Other	1,634			1,687
Unamortized discount	(3,131		)	(2,519		)
Total	667,593			568,291
Less current maturities	1,131			1,235
Total long-term debt	$	666,462		$	567,056
Common Stockholder’s Equity
Common stock  — 1,000,000 shares authorized of $100 par value;
933,000 shares outstanding at Dec. 31, 2015 and 2014, respectively	$	93,300		$	93,300
Additional paid in capital	394,553			322,276
Retained earnings	302,741			282,398
Accumulated other comprehensive loss	(209		)	(285		)
Total common stockholder’s equity	$	790,385		$	697,689

^(a)  Resource recovery financing

See Notes to Consolidated Financial Statements

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Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Business and System of Accounts— NSP-Wisconsin is 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 has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin's proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin's proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages.

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 or potential disallowances, AROs, certain 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 or OCI, 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 sheets.  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.

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NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas, electric fuel and purchased energy 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. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.

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.

For operations in the state of Wisconsin, NSP-Wisconsin is required to contribute 1.2 percent of its three-year average annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates, and there is no financial incentive provided to the utility. The PSCW has full oversight of Focus on Energy including auditing and verification of programs. The program portfolio is outsourced to a third-party administrator who subcontracts as necessary to implement programs.

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. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and 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 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 life studies are performed 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 3.4, 3.3 and 3.5 percent for the years ended Dec. 31, 2015, 2014 and 2013, 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. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.

39

AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. 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. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. 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.

40

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.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in 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.

41

Estimated remediation costs, excluding inflationary increases, are recorded 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 be extended 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 before the related costs are incurred 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, 2015 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 Issued

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s July 2015 deferral of the standard’s required implementation date, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. NSP-Wisconsin does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements.

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Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Wisconsin does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. This guidance will be effective on a retrospective basis, effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Wisconsin does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which removes the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, NSP-Wisconsin does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Accounts receivable, net (a)
Accounts receivable	$	61,506		$	66,217
Less allowance for bad debts	(5,128		)	(5,821		)
	$	56,378		$	60,396

^(a)  Accounts receivable, net includes an immaterial amount due from affiliates for 2015 and 2014, respectively.

(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,785	$	6,494
Fuel	6,528		6,654
Natural gas	8,246		11,537
	$	21,559	$	24,685

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(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	2,411,562		$	2,061,669
Natural gas plant	275,376			255,465
Common and other property	132,329			125,938
CWIP	65,755			231,413
Total property, plant and equipment	2,885,022			2,674,485
Less accumulated depreciation	(1,056,943		)	(1,000,204		)
	$	1,828,079		$	1,674,281

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, 2015
Borrowing limit	$	150
Amount outstanding at period end	10
Average amount outstanding	6
Maximum amount outstanding	18
Weighted average interest rate, computed on a daily basis	0.44		%
Weighted average interest rate at period end	0.70

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	10			78			68
Average amount outstanding	39			46			20
Maximum amount outstanding	122			101			71
Weighted average interest rate, computed on a daily basis	0.44		%	0.27		%	0.31		%
Weighted average interest rate at period end	0.70			0.55			0.27

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, 2015 and 2014, 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.

Credit Agreement — 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 October 2019.

NSP-Wisconsin has the right to request an extension of the 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 46 percent and 48 percent at Dec. 31, 2015 and 2014, respectively. 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.

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• NSP-Wisconsin was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2015 and 2014.

• 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, 2015, NSP-Wisconsin had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	150	$	10	$	140

^(a)  This credit facility matures in October 2019.

^(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, 2015 and 2014.

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, 2015			Dec. 31, 2014
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate	0.87		%	0.51		%

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 2015, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024. In 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

During the next five years, NSP-Wisconsin has long-term debt maturities of $150 million due in 2018.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $5.1 million and $4.3 million, net of amortization, at Dec. 31, 2015 and 2014, 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, 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 $33.3 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 52.6 percent at Dec. 31, 2015 and $2.4 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, 2015:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	154,394	$	6,863	$	1,633	80	%
La Crosse, Wis. to Madison, Wis.	—		—		18,894		37
Total NSP-Wisconsin	$	154,394	$	6,863	$	20,527

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

Consolidated Appropriations Act, 2016- In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following:

• Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;

• PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;

• ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;

• R&E credit was permanently extended; and

• Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.

Tax Increase Prevention Act of 2014— In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:

• The R&E credit was extended for 2014;

• PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

American Taxpayer Relief Act of 2012— In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following:

• The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains;

• The R&E credit was extended for 2012 and 2013;

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• PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for in the period of enactment.

Federal Audit— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. 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, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2015, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2011. As of Dec. 31, 2015, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	4.3		2.9
Total unrecognized tax benefit	$	4.5	$	3.0

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

(Millions of Dollars)	2015			2014			2013
Balance at Jan. 1	$	3.0		$	1.5		$	1.3
Additions based on tax positions related to the current year	1.9			1.9			0.7
Reductions based on tax positions related to the current year	(0.3		)	(0.2		)	—
Additions for tax positions of prior years	0.8			0.1			0.5
Reductions for tax positions of prior years	(0.9		)	(0.2		)	—
Settlements with taxing authorities	—			(0.1		)	(1.0		)
Balance at Dec. 31	$	4.5		$	3.0		$	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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(0.9	)	$	(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 Appeals and audit progress and state audits resume. As the IRS Appeals and audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

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The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2015, 2014 and 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2015, 2014 or 2013.

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)	2015	2014
Federal NOL carryforward	103	49
Federal tax credit carryforwards	5	5
State NOL carryforward	3	3

The federal carryforward periods expire between 2021 and 2035.  The state carryforward periods expire between 2027 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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.8		4.9		5.0
Change in unrecognized tax benefits	0.1		—		—
Tax credits recognized	(0.7	)	(0.7	)	(0.9	)
Regulatory differences — utility plant items	(1.7	)	(1.6	)	(0.9	)
Other, net	(0.3	)	(0.1	)	(0.2	)
Effective income tax rate	37.2	%	37.5	%	38.0	%

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

(Thousands of Dollars)	2015			2014			2013
Current federal tax expense (benefit)	$	(4,715	)	$	(3,932	)	$	5,902
Current state tax expense	2,150			453			4,628
Current change in unrecognized tax expense	1,498			1,013			754
Deferred federal tax expense	40,580			38,321			23,794
Deferred state tax expense	6,675			8,042			2,720
Deferred change in unrecognized tax (benefit)	(1,422		)	(967		)	(725		)
Deferred investment tax credits	(528		)	(527		)	(664		)
Total income tax expense	$	44,238		$	42,403		$	36,409

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

(Thousands of Dollars)	2015			2014			2013
Deferred tax expense excluding items below	$	51,084		$	49,793		$	27,516
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(5,200		)	(4,346		)	(1,676		)
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	45,833		$	45,396		$	25,789

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

(Thousands of Dollars)	2015		2014
Deferred tax liabilities:
Difference between book and tax bases of property	$	382,592	$	319,265
Regulatory assets	78,233		72,670
Employee benefits	18,028		18,691
Other	10,190		14,453
Total deferred tax liabilities	$	489,043	$	425,079
Deferred tax assets:
Environmental remediation	$	37,938	$	43,207
NOL carryforward	37,508		18,283
Regulatory liabilities	9,328		10,460
Deferred investment tax credits	5,312		5,628
Tax credit carryforward	4,760		4,515
Other	3,134		3,007
Total deferred tax assets	$	97,980	$	85,100
Net deferred tax liability	$	391,063	$	339,979

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 71 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2015, NSP-Wisconsin had 400 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.

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Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. Preferred stock is valued using recent trades and quoted prices of similar securities. 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. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, 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, 2015 and 2014 were $41.8 million and $46.5 million, respectively, of which $0.7 million and $0.8 million, respectively, was attributable to NSP-Wisconsin. In 2015 and 2014, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $9.5 million and $4.7 million, respectively, of which amounts attributable to NSP-Wisconsin were immaterial. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

• Investment returns in 2015, 2014 and 2013 were below the assumed level of 7.25 percent for all years; and

• In 2016, NSP-Wisconsin’s expected investment-return assumption is 7.10 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 at Dec. 31 for the upcoming year:

	2015		2014
Domestic and international equity securities	41	%	39	%
Long-duration fixed income and interest rate swap securities	23		23
Short-to-intermediate fixed income securities	14		14
Alternative investments	20		22
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	6,005	$	—	$	—	$	6,005
Derivatives	—		89		—		89
Government securities	—		13,048		—		13,048
Corporate bonds	—		10,454		—		10,454
Asset-backed securities	—		101		—		101
Common stock	4,213		—		—		4,213
Private equity investments	—		—		5,967		5,967
Commingled funds	—		76,817		—		76,817
Real estate	—		—		2,413		2,413
Other	—		207		—		207
Total	$	10,218	$	100,716	$	8,380	$	119,314

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	7,910	$	—		$	—	$	7,910
Derivatives	—		28			—		28
Government securities	—		16,084			—		16,084
Corporate bonds	—		13,231			—		13,231
Asset-backed securities	—		162			—		162
Mortgage-backed securities	—		475			—		475
Common stock	4,424		—			—		4,424
Private equity investments	—		—			7,078		7,078
Commingled funds	—		81,806			—		81,806
Real estate	—		—			2,510		2,510
Securities lending collateral obligation and other	—		(995		)	—		(995		)
Total	$	12,334	$	110,791		$	9,588	$	132,713

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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, 2015, 2014 and 2013:

(Thousands of Dollars)	Jan. 1, 2015		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer Out of Level 3		Dec. 31, 2015
Private equity investments	$	7,078	$	1,326	$	(1,836	)	$	(601	)	$	—	$	5,967
Real estate	2,510		334		(556		)	125			—		2,413
Total	$	9,588	$	1,660	$	(2,392	)	$	(476	)	$	—	$	8,380

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	7,502	$	1,197	$	(1,197	)	$	(424	)	$	—	$	7,078
Real estate	2,299		166		(234		)	279			—		2,510
Total	$	9,801	$	1,363	$	(1,431	)	$	(145	)	$	—	$	9,588

(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	$	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.

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)	2015			2014
Accumulated Benefit Obligation at Dec. 31	$	140,917		$	153,590
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	165,669		$	163,930
Service cost	4,759			4,527
Interest cost	6,520			7,257
Actuarial (gain) loss	(11,159		)	9,126
Benefit payments	(13,244		)	(19,171		)
Obligation at Dec. 31	$	152,545		$	165,669

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	132,713		$	136,935
Actual (loss) return on plan assets	(5,087		)	6,916
Employer contributions	4,932			8,033
Benefit payments	(13,244		)	(19,171		)
Fair value of plan assets at Dec. 31	$	119,314		$	132,713

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(33,231	)	$	(32,956	)

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

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(Thousands of Dollars)	2015		2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	86,614	$	90,007
Prior service cost	556		667
Total	$	87,170	$	90,674

(Thousands of Dollars)	2015		2014
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	$	6,300	$	6,728
Noncurrent regulatory assets	80,870		83,946
Total	$	87,170	$	90,674

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.66	%	4.11	%
Expected average long-term increase in compensation level	4.00		3.75
Mortality table	RP 2014		RP 2014

Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. NSP-Wisconsin has reviewed its own population through a credibility analysis and adopted the RP 2014 table, with modifications, based on its population and specific experience. During 2015, a new projection table was released (MP 2015). NSP-Wisconsin evaluated the updated projection table and concluded that the methodology adopted at Dec. 31, 2014 is consistent with the recently updated table and continues to be representative of its population.

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. Required contributions were made in 2013 through 2016 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

• $125.0 million in January 2016, of which $7.4 million was attributable to NSP-Wisconsin;

• $90.1 million in 2015, of which $4.9 million was attributable to NSP-Wisconsin;

• $130.6 million in 2014, of which $8.0 million was attributable to NSP-Wisconsin; and

• $192.4 million in 2013, of which $11.3 million was attributable to NSP-Wisconsin.

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

Plan Amendments — In 2015 and 2014, there were no plan amendments made which affected the benefit obligation. 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.

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	4,759		$	4,527		$	5,682
Interest cost	6,520			7,257			6,924
Expected return on plan assets	(9,483		)	(9,642		)	(9,995		)
Amortization of prior service cost	111			111			417
Amortization of net loss	6,804			6,617			7,924
Net periodic pension cost	$	8,711		$	8,870		$	10,952

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	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.11	%	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75		3.75
Expected average long-term rate of return on assets	7.25		7.25		7.25

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to NSP-Wisconsin were $1.9 million, $1.7 million and $2.2 million in 2015, 2014 and 2013, 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 2015 pension cost calculations is 7.10 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 $1.4 million in 2015 and 2014, and $1.3 million in 2013.

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. NSP-Wisconsin discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

Regulatory agencies for nearly all retail 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. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:

	2015		2014
Domestic and international equity securities	25	%	25	%
Short-to-intermediate fixed income securities	57		57
Alternative investments	13		13
Cash	5		5
Total	100	%	100	%

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. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total 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. Market volatility is not considered to be a material factor in postretirement health care costs.

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The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	18	$	—	$	—	$	18
Government securities	—		37		—		37
Insurance contracts	—		44		—		44
Corporate bonds	—		68		—		68
Asset-backed securities	—		27		—		27
Mortgage-backed securities	—		33		—		33
Commingled funds	—		191		—		191
Total	$	18	$	400	$	—	$	418

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	28	$	—		$	—	$	28
Government securities	—		52			—		52
Insurance contracts	—		54			—		54
Corporate bonds	—		59			—		59
Asset-backed securities	—		4			—		4
Mortgage-backed securities	—		12			—		12
Commingled funds	—		304			—		304
Other	—		(1		)	—		(1		)
Total	$	28	$	484		$	—	$	512

For the year ended Dec. 31, 2015 and 2014 there were no assets transferred in or out of Level 3. The following table presents the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the year ended 2013:

(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.

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)	2015			2014
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	16,768		$	17,153
Service cost	29			35
Interest cost	653			791
Medicare subsidy reimbursements	13			2
Plan participants’ contributions	130			284
Actuarial gain	(1,645		)	(38		)
Benefit payments	(1,230		)	(1,459		)
Obligation at Dec. 31	$	14,718		$	16,768

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(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	512		$	746
Actual loss on plan assets	(12		)	(15		)
Plan participants’ contributions	130			284
Employer contributions	1,018			956
Benefit payments	(1,230		)	(1,459		)
Fair value of plan assets at Dec. 31	$	418		$	512

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status	$	(14,300	)	$	(16,256	)
Current liabilities	(1,017		)	(1,022		)
Noncurrent liabilities	(13,283		)	(15,234		)
Net postretirement amounts recognized on consolidated balance sheets	$	(14,300	)	$	(16,256	)

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	8,402		$	10,461
Prior service credit	(2,485		)	(2,836		)
Total	$	5,917		$	7,625

(Thousands of Dollars)	2015		2014
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	$	99	$	95
Noncurrent regulatory assets	5,818		7,530
Total	$	5,917	$	7,625

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.65	%	4.08	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	6.00	%	6.50	%

Effective Jan. 1, 2016, the initial medical trend rate was decreased from 6.5 percent to 6.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is three 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	$	1,420	$	(1,208	)
Service and interest components	77		(65		)

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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. Xcel Energy, which includes NSP-Wisconsin, contributed $18.3 million, $17.1 million and $17.6 million during 2015, 2014 and 2013, respectively, of which $1.0 million, $1.0 million and $1.5 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $12.3 million during 2016, of which $1.4 million is attributable to NSP-Wisconsin.

Plan Amendments — In 2015 and 2014, there were no plan amendments made which affected the benefit obligation.

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	29		$	35		$	25
Interest cost	653			791			760
Expected return on plan assets	(30		)	(52		)	(42		)
Amortization of transition obligation	—			—			1
Amortization of prior service credit	(351		)	(351		)	(351		)
Amortization of net loss	456			666			963
Net periodic postretirement benefit cost	$	757		$	1,089		$	1,356

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.08	%	4.82	%	4.10	%
Expected average long-term rate of return on assets	5.80		7.08		7.11

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
2016	$	11,278	$	1,443	$	8	$	1,435
2017	11,893		1,324		6		1,318
2018	11,746		1,278		5		1,273
2019	12,920		1,244		4		1,240
2020	13,404		1,203		4		1,199
2021-2025	62,859		5,200		19		5,181

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.

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Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2015, 2014 and 2013. 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)	2015		2014		2013
Multiemployer plan contributions:
Pension	$	944	$	156	$	130
Total	$	944	$	156	$	130

8. Other Income, Net

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

(Thousands of Dollars)	2015			2014			2013
Interest income	$	332		$	368		$	538
Other nonoperating income	789			321			152
Insurance policy expense	(228		)	(409		)	(427		)
Other nonoperating expense	(10		)	(10		)	(10		)
Other income, net	$	883		$	270		$	253

9. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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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, 2015, 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:

(Amounts in Thousands)(a)(b)	2015	2014
MMBtu of natural gas	388	18

^(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)	2015			2014			2013
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(285	)	$	(361	)	$	(437	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			76			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(209	)	$	(285	)	$	(361	)

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, 2015, 2014 and 2013.

During the years ended Dec. 31, 2015 and 2013 changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.7 million and $0.1 million, recognized as regulatory assets and liabilities. During the year ended Dec. 31, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.1 million, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

During the years ended Dec. 31, 2015 and 2013, $1.4 million and $0.7 million of natural gas commodity derivatives settlement losses were recognized and immaterial gains were recognized for the year ended Dec. 31, 2014, 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, 2015, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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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, 2015
	Fair Value						Fair Value Total		Counterparty Netting(a)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total(b)
Current derivative assets
Natural gas commodity	$	—	$	15	$	—	$	15	$	(11	)	$	4
Total current derivative assets	$	—	$	15	$	—	$	15	$	(11	)	$	4
Current derivative liabilities
Natural gas commodity	$	—	$	194	$	—	$	194	$	(11	)	$	183
Total current derivative liabilities	$	—	$	194	$	—	$	194	$	(11	)	$	183

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(a)
(Thousands of Dollars)	Level 1		Level 2		Level 3						Total(c)
Current derivative assets
Natural gas commodity	$	—	$	52	$	—	$	52	$	—	$	52

^(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, 2015 and 2014.  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 $2.4 million and other current liabilities balance of $15.8 million at Dec. 31, 2015 in the consolidated balance sheets.

^(c)  Included in other current assets balance of $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2015 and 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2015				2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	667,593	$	742,565	$	568,291	$	670,665

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, 2015 and 2014, 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

NSP-Wisconsin – Wisconsin 2016 Electric and Gas Rate Case—In May 2015, NSP-Wisconsin filed a request with the PSCW seeking an increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent, effective Jan. 1, 2016. The rate filing was based on a 2016 forecast test year, a ROE of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

In December 2015, the PSCW approved an electric rate increase of approximately $7.6 million, or 1.1 percent, and a natural gas rate increase of $4.2 million, or 3.6 percent, based on a 10.0 percent ROE and an equity ratio of 52.5 percent. New rates went into effect in January 2016. As shown below, NSP-Wisconsin received approximately 65 percent of the non-fuel and purchased power portion of its requested electric rate increase and 71 percent of its requested natural gas rate increase.

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The major components of the requested rate increases and the PSCW's approval are summarized as follows:

Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	23.0		$	13.9
ROE & other capital structure adjustments	—			(3.8		)
Generation and transmission expenses (excluding fuel and purchased power)	37.2			42.7
O&M expenses	11.1			3.2
Sales forecast	(27.0		)	(27.0		)
Rate increase - non-fuel and purchased power	44.3			29.0
Rate reduction - fuel and purchased power	(16.9		)	(21.4		)
Total electric rate increase	$	27.4		$	7.6

Natural Gas Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	3.7		$	3.7
ROE & other capital structure adjustments	—			(0.4		)
O&M expenses	3.2			1.9
Environmental remediation expenses	2.9			2.9
Sales forecast	(3.9		)	(3.9		)
Total natural gas rate increase	$	5.9		$	4.2

Recently Concluded Regulatory Proceedings — MPUC

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 MW. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used and useful for 2014.  As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.

Pending Regulatory Proceedings — FERC

MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in 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.

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Subsequently, the FERC adopted a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent. The FERC staff recommended a ROE of 8.68 percent. The MISO TOs recommended a ROE not less than 10.8 percent. In December 2015, an ALJ initial decision was issued recommending a ROE of 10.32 percent. Briefs on exceptions challenging the ALJ recommendation were filed in January 2016. A FERC order is expected to be issued later in 2016.

Certain MISO TOs separately requested FERC approval of a 50 basis point ROE adder for RTO membership, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder and FERC action is pending.

In February 2015, certain intervenors filed a second complaint to reduce the MISO region ROE to 8.67 percent, prior to an adder.  FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The complainants and intervenors filed direct testimony in September 2015, the MISO TOs filed answering testimony in October 2015 and FERC staff filed testimony in November 2015. In January 2016, all parties updated their ROE analyses. The complainants and intervenors recommended ROEs between 8.72 percent and 9.32 percent while FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.96 percent. Hearings were held before an ALJ in February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision expected in late 2016 or 2017.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of Dec. 31, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million annually for the NSP System.

11. Commitments and Contingencies

Commitments

Fuel Contracts— NSP-Wisconsin has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2016 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, 2015 are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2016	$	6.7	$	9.7	$	13.1
2017	2.5		0.2		10.4
2018	2.5		—		4.7
2019	0.8		—		3.1
2020	0.8		—		1.9
Thereafter	2.5		—		11.6
Total (a)	$	15.8	$	9.9	$	44.8

^(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.

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Leases— NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business. These leases, primarily for office space, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $1.1 million, $1.3 million and $1.4 million for 2015, 2014 and 2013, respectively.

Future commitments under operating leases are:

(Millions of Dollars)
2016	$	0.9
2017	1.0
2018	0.9
2019	0.9
2020	0.8
Thereafter	7.0
Total	$	11.5

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, 2015		Dec. 31, 2014
Current assets	$	377	$	246
Property, plant and equipment, net	2,199		2,278
Other noncurrent assets	127		122
Total assets	$	2,703	$	2,646
Current liabilities	$	1,246	$	1,349
Mortgages and other long-term debt payable	537		486
Other noncurrent liabilities	51		48
Total liabilities	$	1,834	$	1,883

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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 $13.5 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 $13.1 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 $19.0 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 $19.9 million for business interruption insurance and $43.7 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
Guarantee of customer loans for the Farm Rewiring Program	$	1.0	$	0.1	2020	(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 wastes to that site.

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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 Site) includes property owned by NSP-Wisconsin, previously operated by a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

In 2010, the EPA issued its Record of Decision (ROD), including their preferred remedy for the Sediments which is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). A wet conventional dredging only remedy (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study, is another possibility.

In 2012, under a settlement agreement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site). Fieldwork began in 2012 and continues. Excavation and containment remedies are complete. A long-term groundwater pump and treatment program is now underway. The final design was approved by the EPA in late 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $65 million, of which approximately $47 million has already been spent.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and which remedy will be implemented. The EPA’s ROD 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. NSP-Wisconsin believes the Hybrid Remedy is not safe or feasible to implement. In 2015, NSP-Wisconsin constructed a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. The wet dredge pilot study is anticipated to commence in spring 2016.

As a result of litigation and settlements approved by the U.S. District Court for the Western District of Wisconsin in 2015, three other PRPs have contributed $15.9 million to the remediation of the site. Settlements in principle were also reached with the City of Ashland and the County of Ashland in January 2016, and NSP-Wisconsin anticipates that its litigation efforts against other PRPs are complete.

At Dec. 31, 2015 and 2014, NSP-Wisconsin had recorded a liability of $94.4 million and $107.6 million, respectively, for the Site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $17.0 million and $28.9 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 Site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented and whether federal or state funding may be directed to help offset remediation costs at the Site.

NSP-Wisconsin has deferred the estimated site remediation costs as a regulatory asset. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In a December 2012 decision, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period, and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2015, the PSCW approved NSP-Wisconsin’s 2016 rate case request for an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million.

Other MGP Sites— NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where regulated materials may have been deposited. NSP-Wisconsin has identified one site where former MGP activities may have resulted in site contamination and is under current investigation. At this MGP site, there are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the remediation at this site will continue through at least 2016. NSP-Wisconsin had accrued $0.2 million for this site at Dec. 31, 2015 and 2014, 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.

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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 September 2015, the EPA issued a final 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. NSP-Wisconsin has reviewed the final rule and is in the process of evaluating whether the costs of compliance could have a material impact on the results of operations, financial position or cash flows. NSP-Wisconsin believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Section 316(b)— Section 316(b) of 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. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Many of the compliance requirements depend on site-specific determinations by state regulators; therefore, the exact cost is somewhat uncertain. NSP-Wisconsin believes at least two plants could be required by state regulators to make improvements to reduce entrainment. NSP-Wisconsin estimates the likely cost for complying with impingement requirements may be incurred between 2016 and 2027 and is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.

Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In October 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  States must develop implementation plans by September 2016, with the possibility of an extension to September 2018, or the EPA will prepare a federal plan for the state.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.  The CPP is currently being challenged by multiple parties in the D.C. Circuit Court.  In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule as well as ordered expedited review of the CPP, with briefings to be completed and oral arguments held by June 2016.  Following the D.C. Circuit Court’s denial of motions for stay, multiple parties filed requests for stay with the U.S. Supreme Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until, first, the D.C. Circuit Court and then the U.S. Supreme Court have ruled on the challenges to the CPP.

NSP-Wisconsin has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals.  The CPP could require additional emission reductions in states in which NSP-Wisconsin operates.  If state plans do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs.  Until NSP-Wisconsin has more information about SIPs or knows the requirements of the EPA’s upcoming final rule on federal plans for the states that do not develop related plans, NSP-Wisconsin cannot predict the costs of compliance with the final rule once it takes effect.  NSP-Wisconsin believes compliance costs will be recoverable through regulatory mechanisms.  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 CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

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CSAPR— CSAPR addresses 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, using an emissions trading program. CSAPR compliance in 2015 did not and 2016 is not expected to have a material impact on the results of operations, financial position or cash flows.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone NAAQS and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. If adopted as proposed, the ozone season emission budget for NOx is not expected to impact NSP-Wisconsin.

Revisions to the NAAQS for Ozone— In October 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. Current monitored air quality concentrations in areas of Wisconsin, where NSP-Wisconsin operates, are below the new standard. Therefore, NSP-Wisconsin does not expect a material impact on results of operations, financial position or cash flows.

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 distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. AROs also have been recorded for NSP-Wisconsin steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.

NSP-Wisconsin has recognized an ARO for the retirement costs of natural gas mains and lines and for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks and office buildings.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. No cash flow revisions were necessary, as a result of the final rule, as of Dec. 31, 2015.

A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow Revisions			Ending Balance    Dec. 31, 2015(a)
Electric plant
Steam production asbestos	$	2,049	$	45	$	51		$	2,145
Steam production ash containment	374		14		229			617
Electric distribution	37		1		34			72
Other	412		15		(36		)	391
Natural gas plant
Gas distribution	6,127		240		—			6,367
Common and other property
Common miscellaneous	91		4		—			95
Total liability (b)	$	9,090	$	319	$	278		$	9,687

^(a)  There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

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

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(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow    Revisions(a)		Ending Balance     Dec. 31, 2014 (b)
Electric plant
Steam production asbestos	$	2,005	$	—	$	44	$	—	$	2,049
Steam production ash containment	361		—		13		—		374
Electric distribution	36		—		1		—		37
Other	289		113		10		—		412
Natural gas plant
Gas distribution	75		402		5		5,645		6,127
Common and other property
Common miscellaneous	87		—		3		1		91
Total liability (c)	$	2,853	$	515	$	76	$	5,646	$	9,090

^(a)  In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas distribution.

^(b)  There were no ARO liabilities settled during the year ended Dec. 31, 2014.

^(c)  Included in other long-term liabilities balance in the consolidated balance sheet.

Indeterminate AROs— Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Wisconsin’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2015. Therefore, an ARO has not been recorded for these facilities.

Removal Costs— NSP-Wisconsin records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. 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 time periods over which the amounts were accrued and the changing of rates over 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, 2015 and 2014 were $132 million and $123 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.

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy.  e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The cases were consolidated in U.S. District Court in Nevada.  In 2009, five of the cases were settled and one was dismissed.  The U.S. District Court in 2011 issued an order dismissing entirely six of the remaining seven lawsuits, and partially dismissing the seventh. Plaintiffs appealed the dismissals to the Ninth Circuit, which reversed the District Court. The matter was ultimately heard by the U.S. Supreme Court in early 2015, which agreed with the Ninth Circuit and remanded the matter to the U.S. District Court. In September 2015, the District Court held a status conference and set deadlines for certain litigation related activities in 2016. A trial date has not yet been set, but is not expected to occur prior to late 2016 or early 2017. Xcel Energy and e prime have concluded that a loss is remote with respect to this matter.

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Other Contingencies

See Note 10 for further discussion.

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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	6,702	$	160,699	$	4,376	$	147,793
Pension and retiree medical obligations (a)	7	Various	6,415		86,778		6,837		91,601
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		20,586		—		16,711
State commission adjustments	1	Plant lives	724		12,945		488		11,650
Losses on reacquired debt	4	Term of related debt	803		4,134		801		4,936
Deferred income tax adjustment	1, 6	Typically plant lives	—		2,250		—		1,514
Recoverable purchased natural gas and electric energy costs		Less than one year	1,032		—		6,946		—
Monticello EPU		N/A	—		—		—		5,237
Other		Various	470		1,804		588		1,251
Total regulatory assets			$	16,146	$	289,196	$	20,036	$	280,693

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

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	132,311	$	—	$	123,105
Investment tax credit deferrals	1, 6	Various	—		8,869		—		9,397
Deferred electric production and natural gas costs	1	Less than one year	9,386		—		—		—
DOE settlement	11	One to two years	1,996		—		4,931		—
Conservation programs	1	Less than one year	339		—		1,010		—
Excess depreciation reserve		Less than one year	60		—		10,999		—
Other		Various	—		109		—		172
Total regulatory liabilities			$	11,781	$	141,289	$	16,940	$	132,674

At Dec. 31, 2015 and 2014, approximately $1.0 million and $12.1 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes Monticello EPU costs and recoverable purchased natural gas and electric energy costs.

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13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2015			Year Ended Dec. 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(285	)	$	(361	)
Losses reclassified from net accumulated other comprehensive loss	76			76
Net current period OCI	76			76
Accumulated other comprehensive loss at Dec. 31	$	(209	)	$	(285	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2015				Year Ended Dec. 31, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	127		(a)	$	127		(a)
Total, pre-tax	127				127
Tax benefit	(51		)		(51		)
Total amounts reclassified, net of tax	$	76			$	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.

• 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.

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2015
Operating revenues (a)	$	834,998	$	120,147	$	1,396	$	—		$	956,541
Intersegment revenues	419		498		—		(917		)	—
Total revenues	$	835,417	$	120,645	$	1,396	$	(917	)	$	956,541
Depreciation and amortization	$	77,036	$	14,034	$	175	$	—		$	91,245
Interest charges and financing costs	26,494		2,637		90		—			29,221
Income tax expense	40,654		2,501		1,083		—			44,238
Net Income	69,398		4,862		376		—			74,636

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2014
Operating revenues (a)	$	829,748	$	169,629	$	1,085		$	—		$	1,000,462
Intersegment revenues	497		4,885		—			(5,382		)	—
Total revenues	$	830,245	$	174,514	$	1,085		$	(5,382	)	$	1,000,462
Depreciation and amortization	$	65,978	$	13,501	$	175		$	—		$	79,654
Interest charges and financing costs	23,448		2,358		107			—			25,913
Income tax expense (benefit)	39,621		5,993		(3,211		)	—			42,403
Net Income	59,060		8,714		2,868			—			70,642

(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	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

^(a)  Operating revenuesinclude $163 million, $145 million and $137 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013 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)	2015		2014		2013
Operating revenues:
Electric	$	163,255	$	145,102	$	136,917
Operating expenses:
Purchased power (a)	419,028		430,666		416,173
Transmission expense	54,070		43,876		42,460
Natural gas purchased for resale	45		90		97
Other operating expenses — paid to Xcel Energy Services Inc.	93,890		84,224		61,531
Interest expense	2		30		22

^(a)  Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

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

	2015				2014
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	18,268	$	—	$	17,333
PSCo	—		71		—		22
SPS	71		—		31		—
Other subsidiaries of Xcel Energy Inc.	—		6,199		—		9,169
	$	71	$	24,538	$	31	$	26,524

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	273,960	$	216,813	$	236,161	$	229,607
Operating income	39,549		25,069		47,532		27,809
Net income	22,267		12,512		26,232		13,625

	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		Dec. 31, 2014
Operating revenues	$	285,142	$	228,114	$	231,046	$	256,160
Operating income	42,571		23,730		37,540		27,787
Net income	24,235		12,022		20,030		14,355

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

None.

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Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Wisconsin maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Dec. 31, 2015, based on an evaluation carried out under the supervision and with the participation of NSP-Wisconsin’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Wisconsin’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Wisconsin’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Wisconsin’s internal control over financial reporting. NSP-Wisconsin maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting.  NSP-Wisconsin has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.  During the year and in preparation for issuing its report for the year ended Dec. 31, 2015 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.

Effective January 2016, NSP-Wisconsin implemented the general ledger modules of a new enterprise resource planning (“ERP”) system to improve certain financial and related transaction processes. During 2016 and 2017, NSP-Wisconsin will continue implementing additional modules and expects to begin conversion of existing work management system to this same ERP system. In connection with this ongoing implementation, NSP-Wisconsin is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures. NSP-Wisconsin does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

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

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2016 Annual Meeting of Shareholders, which is incorporated by reference.

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Item 14 — Principal Accountant Fees and Services

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm - Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2016 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2016. Such information set forth under such heading is incorporated herein by this reference hereto.

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, 2015
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2015, 2014 and 2013.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2015, 2014 and 2013.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2015, 2014 and 2013.
	Consolidated Balance Sheets — As of Dec. 31, 2015 and 2014.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2015, 2014 and 2013.
	Consolidated Statements of Capitalization — As of Dec. 31, 2015 and 2014.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2015, 2014 and 2013.
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, between NSP-Wisconsin and Firstar Trust Company, as Trustee (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) for the quarter ended Sept. 30, 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 Trust 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)).
4.08*	Supplemental Trust Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.30 percent First Mortgage Bonds, Series due June 15, 2024. (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated June 23, 2014 (file no. 001-03140)).

74

10.01*+	Xcel Energy Inc. Nonqualified 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 and Change-in-Control 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 Inc. 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 Inc. 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 Inc. 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 Inc. 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 Inc. 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 Inc. 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.13*+	Xcel Energy Inc. 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).
10.14a*+	Xcel Energy Inc. 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).
10.14b*+	Xcel Energy Inc. 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).
10.15*+	Xcel Energy Inc. 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 Inc. 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) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.18*+	First Amendment effective Nov. 29, 2011 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.19*+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Inc. 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).
10.20*+	First Amendment dated Feb. 20, 2013 to the Xcel Energy Inc. 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. 2005 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. Nonqualified 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 Inc. 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).

75

10.25*	Amended and Restated Credit Agreement, dated as of Oct. 14, 2014 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 (Exhibit 99.05 to Form 8-K of Xcel Energy, dated Oct. 14, 2014 (file no. 001-03034)).
10.26*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2015).
10.27*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. (As First Effective May 20, 2015) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.02 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.28*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.03 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.29*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award Agreement. (Exhibit 10.28 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).
10.30*+	Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.29 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).
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, 2015 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.

76

SCHEDULE II

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2015, 2014 AND 2013

(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:
2015	$	5,821	$	3,947	$	1,161	$	5,801	$	5,128
2014	4,911		4,431		1,269		4,790		5,821
2013	4,333		3,988		1,199		4,609		4,911

^(a)  Recovery of amounts previously written off.

^(b)  Deductions relate primarily to bad debt write-offs.

77

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. 22, 2016	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Executive 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/ BEN FOWKE	/s/ MARK E. STOERING
Ben Fowke	Mark E. Stoering
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ JEFFREY S. SAVAGE
Teresa S. Madden	Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director	Senior Vice President, Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ MARVIN E. MCDANIEL, JR.
Marvin E. McDaniel, Jr.
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.

78

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
	2015		2014		2013		2012		2011
Earnings, as defined:
Pretax income	$	118,874	$	113,045	$	95,877	$	79,509	$	84,620
Add: Fixed charges	33,073		29,686		28,325		25,215		24,628
Total earnings, as defined	$	151,947	$	142,731	$	124,202	$	104,724	$	109,248
Fixed charges, as defined:
Interest charges	$	32,731	$	29,273	$	27,797	$	24,799	$	24,168
Interest component of leases	342		413		528		416		460
Total fixed charges, as defined	$	33,073	$	29,686	$	28,325	$	25,215	$	24,628
Ratio of earnings to fixed charges	4.6		4.8		4.4		4.2		4.4

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-203664-02 on Form S-3 of our report dated February 22, 2016, 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, 2015.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2016

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, 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. 22, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, President and Chief Executive Officer

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. 22, 2016

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive 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, 2015, 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. 22, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, President and Chief Executive Officer

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive 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, 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

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
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, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
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

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Electric	$ 834,998	$ 829,748	$ 789,168
Natural gas	120,147	169,629	132,867
Other	1,396	1,085	1,003
Total operating revenues	956,541	1,000,462	923,038
Operating expenses
Electric fuel and purchased power, non-affiliates	10,795	19,595	18,129
Purchased power, affiliates	419,028	425,471	416,173
Cost of natural gas sold and transported	70,988	114,250	81,572
Operating and maintenance expenses	179,413	191,213	175,522
Conservation program expenses	11,695	11,537	12,333
Depreciation and amortization	91,245	79,654	76,897
Taxes (other than income taxes)	28,181	27,114	25,231
Loss on Monticello LCM/EPU project	5,237	0	0
Total operating expenses	816,582	868,834	805,857
Operating income	139,959	131,628	117,181
Other income, net	883	270	253
Allowance for funds used during construction — equity	7,253	7,060	4,259
Interest charges and financing costs
Interest charges — includes other financing costs of $1,738, $1,570, and $1,538, respectively	32,731	29,273	27,797
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(3,510)	(3,360)	(1,981)
Total interest charges and financing costs	29,221	25,913	25,816
Income before income taxes	118,874	113,045	95,877
Income taxes	44,238	42,403	36,409
Net income	$ 74,636	$ 70,642	$ 59,468

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest charges and financing costs
Other financing costs	$ 1,738	$ 1,570	$ 1,538

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Comprehensive income:
Net income	$ 74,636	$ 70,642	$ 59,468
Derivative instruments:
Reclassification of losses to net income, net of tax of $51 for the years ended Dec. 31, 2015, 2014, and 2013, respectively.	76	76	76
Other comprehensive income	76	76	76
Comprehensive income	$ 74,712	$ 70,718	$ 59,544

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative instruments:
Reclassification of losses to net income, net of tax	$ (51)	$ (51)	$ (51)

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities
Net income	$ 74,636	$ 70,642	$ 59,468
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	92,656	80,875	78,048
Deferred income taxes	45,833	45,396	25,789
Amortization of Investment Tax Credits	(528)	(527)	(664)
Allowance for equity funds used during construction	(7,253)	(7,060)	(4,259)
Loss on Monticello LCM/EPU project	5,237	0	0
Provision for bad debts	3,947	4,431	3,988
Net derivative losses (gains)	482	10	(279)
Changes in operating assets and liabilities:
Accounts receivable	71	(5,558)	(12,702)
Accrued unbilled revenues	5,869	(1,933)	(2,496)
Inventories	3,126	(3,210)	(1,879)
Other current assets	7,135	(3,501)	(3,749)
Accounts payable	(7,626)	2,936	(1,811)
Net regulatory assets and liabilities	(27,114)	(34,697)	(2,062)
Other current liabilities	5,147	(911)	7,589
Pension and other employee benefit obligations	(3,177)	(6,134)	(8,759)
Change in other noncurrent assets	209	(113)	232
Change in other noncurrent liabilities	716	2,534	1,119
Net cash provided by operating activities	199,366	143,180	137,573
Investing activities
Utility capital/construction expenditures	(251,797)	(288,209)	(201,278)
Allowance for equity funds used during construction	7,253	7,060	4,259
Other, net	(224)	(166)	(421)
Net cash used in investing activities	(244,768)	(281,315)	(197,440)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	(68,000)	10,000	29,000
Proceeds from notes payable to affiliates	0	30	0
Repayments Of Notes Payable To Affiliates	0	0	(80)
Proceeds from Issuance of Long-term Debt	97,969	98,534	0
Repayments of long-term debt	(87)	(107)	(160)
Capital contributions from parent	69,243	73,432	58,977
Dividends paid to parent	(53,929)	(43,818)	(30,980)
Net cash provided by financing activities	45,196	138,071	56,757
Net change in cash and cash equivalents	(206)	(64)	(3,110)
Cash and cash equivalents at beginning of period	1,285	1,349	4,459
Cash and cash equivalents at end of period	1,079	1,285	1,349
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(27,491)	(24,442)	(24,376)
Cash received (paid) for income taxes, net	5,762	3,474	(9,842)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 16,729	$ 35,267	$ 27,222

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents		$ 1,079	$ 1,285
Accounts receivable, net	[1]	56,378	60,396
Accrued unbilled revenues		47,698	53,567
Inventories		21,559	24,685
Regulatory assets		16,146	20,036
Prepaid taxes		25,976	28,628
Deferred income taxes		3,138	8,201
Prepayments and other		2,387	6,918
Total current assets		174,361	203,716
Property, plant and equipment, net		1,828,079	1,674,281
Other assets
Regulatory assets		289,196	280,693
Other investments		4,042	3,818
Other		5,211	4,612
Total other assets		298,449	289,123
Total assets		2,300,889	2,167,120
Current liabilities
Current portion of long-term debt		1,131	1,235
Short-term debt		10,000	78,000
Notes payable to affiliates		500	500
Accounts payable		34,317	61,530
Accounts payable to affiliates		24,538	26,524
Dividends payable to parent		15,322	14,957
Regulatory liabilities		11,781	16,940
Environmental liabilities		17,155	29,116
Accrued interest		7,945	7,658
Other		15,778	12,265
Total current liabilities		138,467	248,725
Deferred credits and other liabilities
Deferred Tax Liabilities, Net, Noncurrent		393,569	348,180
Deferred investment tax credits		8,560	9,089
Regulatory liabilities		141,289	132,674
Environmental liabilities		77,441	78,620
Customer advances		18,480	17,623
Pension and employee benefit obligations		49,889	51,313
Other		16,347	16,151
Total deferred credits and other liabilities		$ 705,575	$ 653,650
Commitments and contingencies
Capitalization
Long-term debt		$ 666,462	$ 567,056
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2015 and 2014, respectively		93,300	93,300
Additional paid in capital		394,553	322,276
Retained earnings		302,741	282,398
Accumulated other comprehensive loss		(209)	(285)
Total common stockholder’s equity		790,385	697,689
Total liabilities and equity		$ 2,300,889	$ 2,167,120

[1] Accounts receivable, net includes an immaterial amount due from affiliates for 2015 and 2014, respectively.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
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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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2012	$ 517,106	$ 93,300	$ 189,867	$ 234,376	$ (437)
Balance (in shares) at Dec. 31, 2012		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
Comprehensive income:
Net income	70,642			70,642
Other comprehensive income	76				76
Common dividends declared to parent	(50,743)			(50,743)
Contribution of capital by parent	73,432		73,432
Ending Balance at Dec. 31, 2014	$ 697,689	$ 93,300	322,276	282,398	(285)
Balance (in shares) at Dec. 31, 2014	933,000	933,000
Comprehensive income:
Net income	$ 74,636			74,636
Other comprehensive income	76				76
Common dividends declared to parent	(54,293)			(54,293)
Contribution of capital by parent	72,277		72,277
Ending Balance at Dec. 31, 2015	$ 790,385	$ 93,300	$ 394,553	$ 302,741	$ (209)
Balance (in shares) at Dec. 31, 2015	933,000	933,000

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CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount		$ (3,131)	$ (2,519)
Total long-term debt, including current maturities		667,593	568,291
Less: current maturities		1,131	1,235
Total long-term debt		666,462	567,056
Common Stockholders' Equity
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2015 and 2014, respectively		93,300	93,300
Additional paid in capital		394,553	322,276
Retained earnings		302,741	282,398
Accumulated other comprehensive loss		(209)	(285)
Total common stockholder’s equity		790,385	697,689
First Mortgage Bonds | Series Due Oct. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		150,000	150,000
First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		200,000	100,000
First Mortgage Bonds | Series Due Sept. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		200,000	200,000
First Mortgage Bonds | Series Due Oct. 1, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		100,000	100,000
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	[1]	18,600	18,600
Fort McCoy System Acquisition | Due Oct. 15, 2030
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		490	523
Other
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		$ 1,634	$ 1,687

[1] Resource recovery financing

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Common Stockholders Equity [Abstract]
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
First Mortgage Bonds | Series Due Oct. 1, 2018
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	5.25%	5.25%
Debt instrument, maturity date	Oct. 01, 2018	Oct. 01, 2018
First Mortgage Bonds | Series Due June 15, 2024
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	3.30%	3.30%
Debt instrument, maturity date	Jun. 15, 2024	Jun. 15, 2024
First Mortgage Bonds | Series Due Sept. 1, 2038
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	6.375%	6.375%
Debt instrument, maturity date	Sep. 01, 2038	Sep. 01, 2038
First Mortgage Bonds | Series Due Oct. 1, 2042
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	3.70%	3.70%
Debt instrument, maturity date	Oct. 01, 2042	Oct. 01, 2042
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	6.00%	6.00%
Debt instrument, maturity date	Nov. 01, 2021	Nov. 01, 2021
Fort McCoy System Acquisition | Due Oct. 15, 2030
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)	7.00%	7.00%
Debt instrument, maturity date	Oct. 15, 2030	Oct. 15, 2030

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Business and System of Accounts— NSP-Wisconsin is 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 has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin's proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin's proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages.

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 or potential disallowances, AROs, certain 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 or OCI, 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 sheets.  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, electric fuel and purchased energy 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. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.

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.

For operations in the state of Wisconsin, NSP-Wisconsin is required to contribute 1.2 percent of its three-year average annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates, and there is no financial incentive provided to the utility. The PSCW has full oversight of Focus on Energy including auditing and verification of programs. The program portfolio is outsourced to a third-party administrator who subcontracts as necessary to implement programs.

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. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and 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 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 life studies are performed 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 3.4, 3.3 and 3.5 percent for the years ended Dec. 31, 2015, 2014 and 2013, 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. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.

AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. 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. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. 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.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in 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 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 be extended 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 before the related costs are incurred 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, 2015 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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Accounting Pronouncements

12 Months Ended

Dec. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s July 2015 deferral of the standard’s required implementation date, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. NSP-Wisconsin does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Wisconsin does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. This guidance will be effective on a retrospective basis, effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Wisconsin does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which removes the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, NSP-Wisconsin does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2015

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Accounts receivable, net (a)
Accounts receivable	$	61,506		$	66,217
Less allowance for bad debts	(5,128		)	(5,821		)
	$	56,378		$	60,396

^(a)  Accounts receivable, net includes an immaterial amount due from affiliates for 2015 and 2014, respectively.

(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,785	$	6,494
Fuel	6,528		6,654
Natural gas	8,246		11,537
	$	21,559	$	24,685

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	2,411,562		$	2,061,669
Natural gas plant	275,376			255,465
Common and other property	132,329			125,938
CWIP	65,755			231,413
Total property, plant and equipment	2,885,022			2,674,485
Less accumulated depreciation	(1,056,943		)	(1,000,204		)
	$	1,828,079		$	1,674,281

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2015

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, 2015
Borrowing limit	$	150
Amount outstanding at period end	10
Average amount outstanding	6
Maximum amount outstanding	18
Weighted average interest rate, computed on a daily basis	0.44		%
Weighted average interest rate at period end	0.70

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	10			78			68
Average amount outstanding	39			46			20
Maximum amount outstanding	122			101			71
Weighted average interest rate, computed on a daily basis	0.44		%	0.27		%	0.31		%
Weighted average interest rate at period end	0.70			0.55			0.27

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, 2015 and 2014, 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.

Credit Agreement — 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 October 2019.

NSP-Wisconsin has the right to request an extension of the 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 46 percent and 48 percent at Dec. 31, 2015 and 2014, respectively. 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.

• NSP-Wisconsin was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2015 and 2014.

• 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, 2015, NSP-Wisconsin had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	150	$	10	$	140

^(a)  This credit facility matures in October 2019.

^(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, 2015 and 2014.

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, 2015			Dec. 31, 2014
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate	0.87		%	0.51		%

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 2015, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024. In 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

During the next five years, NSP-Wisconsin has long-term debt maturities of $150 million due in 2018.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $5.1 million and $4.3 million, net of amortization, at Dec. 31, 2015 and 2014, 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, 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 $33.3 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 52.6 percent at Dec. 31, 2015 and $2.4 million in retained earnings was not restricted.

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Joint Ownership of Transmission Facilities

12 Months Ended

Dec. 31, 2015

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, 2015:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	154,394	$	6,863	$	1,633	80	%
La Crosse, Wis. to Madison, Wis.	—		—		18,894		37
Total NSP-Wisconsin	$	154,394	$	6,863	$	20,527

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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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Consolidated Appropriations Act, 2016- In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following:

• Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;

• PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;

• ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;

• R&E credit was permanently extended; and

• Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.

Tax Increase Prevention Act of 2014— In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:

• The R&E credit was extended for 2014;

• PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

American Taxpayer Relief Act of 2012— In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following:

• The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains;

• The R&E credit was extended for 2012 and 2013;

• PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and

• 50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for in the period of enactment.

Federal Audit— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. 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, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2015, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2011. As of Dec. 31, 2015, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	4.3		2.9
Total unrecognized tax benefit	$	4.5	$	3.0

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

(Millions of Dollars)	2015			2014			2013
Balance at Jan. 1	$	3.0		$	1.5		$	1.3
Additions based on tax positions related to the current year	1.9			1.9			0.7
Reductions based on tax positions related to the current year	(0.3		)	(0.2		)	—
Additions for tax positions of prior years	0.8			0.1			0.5
Reductions for tax positions of prior years	(0.9		)	(0.2		)	—
Settlements with taxing authorities	—			(0.1		)	(1.0		)
Balance at Dec. 31	$	4.5		$	3.0		$	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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(0.9	)	$	(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 Appeals and audit progress and state audits resume. As the IRS Appeals and audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

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, 2015, 2014 and 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2015, 2014 or 2013.

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)	2015	2014
Federal NOL carryforward	103	49
Federal tax credit carryforwards	5	5
State NOL carryforward	3	3

The federal carryforward periods expire between 2021 and 2035.  The state carryforward periods expire between 2027 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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.8		4.9		5.0
Change in unrecognized tax benefits	0.1		—		—
Tax credits recognized	(0.7	)	(0.7	)	(0.9	)
Regulatory differences — utility plant items	(1.7	)	(1.6	)	(0.9	)
Other, net	(0.3	)	(0.1	)	(0.2	)
Effective income tax rate	37.2	%	37.5	%	38.0	%

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

(Thousands of Dollars)	2015			2014			2013
Current federal tax expense (benefit)	$	(4,715	)	$	(3,932	)	$	5,902
Current state tax expense	2,150			453			4,628
Current change in unrecognized tax expense	1,498			1,013			754
Deferred federal tax expense	40,580			38,321			23,794
Deferred state tax expense	6,675			8,042			2,720
Deferred change in unrecognized tax (benefit)	(1,422		)	(967		)	(725		)
Deferred investment tax credits	(528		)	(527		)	(664		)
Total income tax expense	$	44,238		$	42,403		$	36,409

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

(Thousands of Dollars)	2015			2014			2013
Deferred tax expense excluding items below	$	51,084		$	49,793		$	27,516
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(5,200		)	(4,346		)	(1,676		)
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	45,833		$	45,396		$	25,789

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

(Thousands of Dollars)	2015		2014
Deferred tax liabilities:
Difference between book and tax bases of property	$	382,592	$	319,265
Regulatory assets	78,233		72,670
Employee benefits	18,028		18,691
Other	10,190		14,453
Total deferred tax liabilities	$	489,043	$	425,079
Deferred tax assets:
Environmental remediation	$	37,938	$	43,207
NOL carryforward	37,508		18,283
Regulatory liabilities	9,328		10,460
Deferred investment tax credits	5,312		5,628
Tax credit carryforward	4,760		4,515
Other	3,134		3,007
Total deferred tax assets	$	97,980	$	85,100
Net deferred tax liability	$	391,063	$	339,979

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

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 71 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2015, NSP-Wisconsin had 400 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. Preferred stock is valued using recent trades and quoted prices of similar securities. 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. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, 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, 2015 and 2014 were $41.8 million and $46.5 million, respectively, of which $0.7 million and $0.8 million, respectively, was attributable to NSP-Wisconsin. In 2015 and 2014, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $9.5 million and $4.7 million, respectively, of which amounts attributable to NSP-Wisconsin were immaterial. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

• Investment returns in 2015, 2014 and 2013 were below the assumed level of 7.25 percent for all years; and

• In 2016, NSP-Wisconsin’s expected investment-return assumption is 7.10 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 at Dec. 31 for the upcoming year:

	2015		2014
Domestic and international equity securities	41	%	39	%
Long-duration fixed income and interest rate swap securities	23		23
Short-to-intermediate fixed income securities	14		14
Alternative investments	20		22
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	6,005	$	—	$	—	$	6,005
Derivatives	—		89		—		89
Government securities	—		13,048		—		13,048
Corporate bonds	—		10,454		—		10,454
Asset-backed securities	—		101		—		101
Common stock	4,213		—		—		4,213
Private equity investments	—		—		5,967		5,967
Commingled funds	—		76,817		—		76,817
Real estate	—		—		2,413		2,413
Other	—		207		—		207
Total	$	10,218	$	100,716	$	8,380	$	119,314

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	7,910	$	—		$	—	$	7,910
Derivatives	—		28			—		28
Government securities	—		16,084			—		16,084
Corporate bonds	—		13,231			—		13,231
Asset-backed securities	—		162			—		162
Mortgage-backed securities	—		475			—		475
Common stock	4,424		—			—		4,424
Private equity investments	—		—			7,078		7,078
Commingled funds	—		81,806			—		81,806
Real estate	—		—			2,510		2,510
Securities lending collateral obligation and other	—		(995		)	—		(995		)
Total	$	12,334	$	110,791		$	9,588	$	132,713

The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2015, 2014 and 2013:

(Thousands of Dollars)	Jan. 1, 2015		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer Out of Level 3		Dec. 31, 2015
Private equity investments	$	7,078	$	1,326	$	(1,836	)	$	(601	)	$	—	$	5,967
Real estate	2,510		334		(556		)	125			—		2,413
Total	$	9,588	$	1,660	$	(2,392	)	$	(476	)	$	—	$	8,380

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	7,502	$	1,197	$	(1,197	)	$	(424	)	$	—	$	7,078
Real estate	2,299		166		(234		)	279			—		2,510
Total	$	9,801	$	1,363	$	(1,431	)	$	(145	)	$	—	$	9,588

(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	$	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.

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)	2015			2014
Accumulated Benefit Obligation at Dec. 31	$	140,917		$	153,590
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	165,669		$	163,930
Service cost	4,759			4,527
Interest cost	6,520			7,257
Actuarial (gain) loss	(11,159		)	9,126
Benefit payments	(13,244		)	(19,171		)
Obligation at Dec. 31	$	152,545		$	165,669

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	132,713		$	136,935
Actual (loss) return on plan assets	(5,087		)	6,916
Employer contributions	4,932			8,033
Benefit payments	(13,244		)	(19,171		)
Fair value of plan assets at Dec. 31	$	119,314		$	132,713

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(33,231	)	$	(32,956	)

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

(Thousands of Dollars)	2015		2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	86,614	$	90,007
Prior service cost	556		667
Total	$	87,170	$	90,674

(Thousands of Dollars)	2015		2014
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	$	6,300	$	6,728
Noncurrent regulatory assets	80,870		83,946
Total	$	87,170	$	90,674

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.66	%	4.11	%
Expected average long-term increase in compensation level	4.00		3.75
Mortality table	RP 2014		RP 2014

Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. NSP-Wisconsin has reviewed its own population through a credibility analysis and adopted the RP 2014 table, with modifications, based on its population and specific experience. During 2015, a new projection table was released (MP 2015). NSP-Wisconsin evaluated the updated projection table and concluded that the methodology adopted at Dec. 31, 2014 is consistent with the recently updated table and continues to be representative of its population.

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. Required contributions were made in 2013 through 2016 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

• $125.0 million in January 2016, of which $7.4 million was attributable to NSP-Wisconsin;

• $90.1 million in 2015, of which $4.9 million was attributable to NSP-Wisconsin;

• $130.6 million in 2014, of which $8.0 million was attributable to NSP-Wisconsin; and

• $192.4 million in 2013, of which $11.3 million was attributable to NSP-Wisconsin.

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

Plan Amendments — In 2015 and 2014, there were no plan amendments made which affected the benefit obligation. 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.

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	4,759		$	4,527		$	5,682
Interest cost	6,520			7,257			6,924
Expected return on plan assets	(9,483		)	(9,642		)	(9,995		)
Amortization of prior service cost	111			111			417
Amortization of net loss	6,804			6,617			7,924
Net periodic pension cost	$	8,711		$	8,870		$	10,952

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.11	%	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75		3.75
Expected average long-term rate of return on assets	7.25		7.25		7.25

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to NSP-Wisconsin were $1.9 million, $1.7 million and $2.2 million in 2015, 2014 and 2013, 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 2015 pension cost calculations is 7.10 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 $1.4 million in 2015 and 2014, and $1.3 million in 2013.

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. NSP-Wisconsin discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

Regulatory agencies for nearly all retail 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. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:

	2015		2014
Domestic and international equity securities	25	%	25	%
Short-to-intermediate fixed income securities	57		57
Alternative investments	13		13
Cash	5		5
Total	100	%	100	%

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. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total 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. Market 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 proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	18	$	—	$	—	$	18
Government securities	—		37		—		37
Insurance contracts	—		44		—		44
Corporate bonds	—		68		—		68
Asset-backed securities	—		27		—		27
Mortgage-backed securities	—		33		—		33
Commingled funds	—		191		—		191
Total	$	18	$	400	$	—	$	418

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	28	$	—		$	—	$	28
Government securities	—		52			—		52
Insurance contracts	—		54			—		54
Corporate bonds	—		59			—		59
Asset-backed securities	—		4			—		4
Mortgage-backed securities	—		12			—		12
Commingled funds	—		304			—		304
Other	—		(1		)	—		(1		)
Total	$	28	$	484		$	—	$	512

For the year ended Dec. 31, 2015 and 2014 there were no assets transferred in or out of Level 3. The following table presents the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the year ended 2013:

(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.

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)	2015			2014
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	16,768		$	17,153
Service cost	29			35
Interest cost	653			791
Medicare subsidy reimbursements	13			2
Plan participants’ contributions	130			284
Actuarial gain	(1,645		)	(38		)
Benefit payments	(1,230		)	(1,459		)
Obligation at Dec. 31	$	14,718		$	16,768

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	512		$	746
Actual loss on plan assets	(12		)	(15		)
Plan participants’ contributions	130			284
Employer contributions	1,018			956
Benefit payments	(1,230		)	(1,459		)
Fair value of plan assets at Dec. 31	$	418		$	512

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status	$	(14,300	)	$	(16,256	)
Current liabilities	(1,017		)	(1,022		)
Noncurrent liabilities	(13,283		)	(15,234		)
Net postretirement amounts recognized on consolidated balance sheets	$	(14,300	)	$	(16,256	)

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	8,402		$	10,461
Prior service credit	(2,485		)	(2,836		)
Total	$	5,917		$	7,625

(Thousands of Dollars)	2015		2014
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	$	99	$	95
Noncurrent regulatory assets	5,818		7,530
Total	$	5,917	$	7,625

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.65	%	4.08	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	6.00	%	6.50	%

Effective Jan. 1, 2016, the initial medical trend rate was decreased from 6.5 percent to 6.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is three 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	$	1,420	$	(1,208	)
Service and interest components	77		(65		)

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. Xcel Energy, which includes NSP-Wisconsin, contributed $18.3 million, $17.1 million and $17.6 million during 2015, 2014 and 2013, respectively, of which $1.0 million, $1.0 million and $1.5 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $12.3 million during 2016, of which $1.4 million is attributable to NSP-Wisconsin.

Plan Amendments — In 2015 and 2014, there were no plan amendments made which affected the benefit obligation.

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	29		$	35		$	25
Interest cost	653			791			760
Expected return on plan assets	(30		)	(52		)	(42		)
Amortization of transition obligation	—			—			1
Amortization of prior service credit	(351		)	(351		)	(351		)
Amortization of net loss	456			666			963
Net periodic postretirement benefit cost	$	757		$	1,089		$	1,356

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.08	%	4.82	%	4.10	%
Expected average long-term rate of return on assets	5.80		7.08		7.11

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
2016	$	11,278	$	1,443	$	8	$	1,435
2017	11,893		1,324		6		1,318
2018	11,746		1,278		5		1,273
2019	12,920		1,244		4		1,240
2020	13,404		1,203		4		1,199
2021-2025	62,859		5,200		19		5,181

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, 2015, 2014 and 2013. 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)	2015		2014		2013
Multiemployer plan contributions:
Pension	$	944	$	156	$	130
Total	$	944	$	156	$	130

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Other Income, Net

12 Months Ended

Dec. 31, 2015

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)	2015			2014			2013
Interest income	$	332		$	368		$	538
Other nonoperating income	789			321			152
Insurance policy expense	(228		)	(409		)	(427		)
Other nonoperating expense	(10		)	(10		)	(10		)
Other income, net	$	883		$	270		$	253

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2015

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, 2015, 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:

(Amounts in Thousands)(a)(b)	2015	2014
MMBtu of natural gas	388	18

^(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)	2015			2014			2013
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(285	)	$	(361	)	$	(437	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			76			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(209	)	$	(285	)	$	(361	)

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, 2015, 2014 and 2013.

During the years ended Dec. 31, 2015 and 2013 changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.7 million and $0.1 million, recognized as regulatory assets and liabilities. During the year ended Dec. 31, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.1 million, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

During the years ended Dec. 31, 2015 and 2013, $1.4 million and $0.7 million of natural gas commodity derivatives settlement losses were recognized and immaterial gains were recognized for the year ended Dec. 31, 2014, 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, 2015, 2014 and 2013. 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, 2015
	Fair Value						Fair Value Total		Counterparty Netting(a)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total(b)
Current derivative assets
Natural gas commodity	$	—	$	15	$	—	$	15	$	(11	)	$	4
Total current derivative assets	$	—	$	15	$	—	$	15	$	(11	)	$	4
Current derivative liabilities
Natural gas commodity	$	—	$	194	$	—	$	194	$	(11	)	$	183
Total current derivative liabilities	$	—	$	194	$	—	$	194	$	(11	)	$	183

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(a)
(Thousands of Dollars)	Level 1		Level 2		Level 3						Total(c)
Current derivative assets
Natural gas commodity	$	—	$	52	$	—	$	52	$	—	$	52

^(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, 2015 and 2014.  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 $2.4 million and other current liabilities balance of $15.8 million at Dec. 31, 2015 in the consolidated balance sheets.

^(c)  Included in other current assets balance of $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2015 and 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2015				2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	667,593	$	742,565	$	568,291	$	670,665

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, 2015 and 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Rate Matters (Notes)

12 Months Ended

Dec. 31, 2015

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

NSP-Wisconsin – Wisconsin 2016 Electric and Gas Rate Case—In May 2015, NSP-Wisconsin filed a request with the PSCW seeking an increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent, effective Jan. 1, 2016. The rate filing was based on a 2016 forecast test year, a ROE of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

In December 2015, the PSCW approved an electric rate increase of approximately $7.6 million, or 1.1 percent, and a natural gas rate increase of $4.2 million, or 3.6 percent, based on a 10.0 percent ROE and an equity ratio of 52.5 percent. New rates went into effect in January 2016. As shown below, NSP-Wisconsin received approximately 65 percent of the non-fuel and purchased power portion of its requested electric rate increase and 71 percent of its requested natural gas rate increase.

The major components of the requested rate increases and the PSCW's approval are summarized as follows:

Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	23.0		$	13.9
ROE & other capital structure adjustments	—			(3.8		)
Generation and transmission expenses (excluding fuel and purchased power)	37.2			42.7
O&M expenses	11.1			3.2
Sales forecast	(27.0		)	(27.0		)
Rate increase - non-fuel and purchased power	44.3			29.0
Rate reduction - fuel and purchased power	(16.9		)	(21.4		)
Total electric rate increase	$	27.4		$	7.6

Natural Gas Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	3.7		$	3.7
ROE & other capital structure adjustments	—			(0.4		)
O&M expenses	3.2			1.9
Environmental remediation expenses	2.9			2.9
Sales forecast	(3.9		)	(3.9		)
Total natural gas rate increase	$	5.9		$	4.2

Recently Concluded Regulatory Proceedings — MPUC

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 MW. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used and useful for 2014.  As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.

Pending Regulatory Proceedings — FERC

MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in 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.

Subsequently, the FERC adopted a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent. The FERC staff recommended a ROE of 8.68 percent. The MISO TOs recommended a ROE not less than 10.8 percent. In December 2015, an ALJ initial decision was issued recommending a ROE of 10.32 percent. Briefs on exceptions challenging the ALJ recommendation were filed in January 2016. A FERC order is expected to be issued later in 2016.

Certain MISO TOs separately requested FERC approval of a 50 basis point ROE adder for RTO membership, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder and FERC action is pending.

In February 2015, certain intervenors filed a second complaint to reduce the MISO region ROE to 8.67 percent, prior to an adder.  FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The complainants and intervenors filed direct testimony in September 2015, the MISO TOs filed answering testimony in October 2015 and FERC staff filed testimony in November 2015. In January 2016, all parties updated their ROE analyses. The complainants and intervenors recommended ROEs between 8.72 percent and 9.32 percent while FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.96 percent. Hearings were held before an ALJ in February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision expected in late 2016 or 2017.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of Dec. 31, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million annually for the NSP System.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Commitments

Fuel Contracts— NSP-Wisconsin has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2016 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, 2015 are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2016	$	6.7	$	9.7	$	13.1
2017	2.5		0.2		10.4
2018	2.5		—		4.7
2019	0.8		—		3.1
2020	0.8		—		1.9
Thereafter	2.5		—		11.6
Total (a)	$	15.8	$	9.9	$	44.8

^(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 $1.1 million, $1.3 million and $1.4 million for 2015, 2014 and 2013, respectively.

Future commitments under operating leases are:

(Millions of Dollars)
2016	$	0.9
2017	1.0
2018	0.9
2019	0.9
2020	0.8
Thereafter	7.0
Total	$	11.5

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, 2015		Dec. 31, 2014
Current assets	$	377	$	246
Property, plant and equipment, net	2,199		2,278
Other noncurrent assets	127		122
Total assets	$	2,703	$	2,646
Current liabilities	$	1,246	$	1,349
Mortgages and other long-term debt payable	537		486
Other noncurrent liabilities	51		48
Total liabilities	$	1,834	$	1,883

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 $13.5 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 $13.1 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 $19.0 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 $19.9 million for business interruption insurance and $43.7 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
Guarantee of customer loans for the Farm Rewiring Program	$	1.0	$	0.1	2020	(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 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 Site) includes property owned by NSP-Wisconsin, previously operated by a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

In 2010, the EPA issued its Record of Decision (ROD), including their preferred remedy for the Sediments which is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). A wet conventional dredging only remedy (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study, is another possibility.

In 2012, under a settlement agreement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site). Fieldwork began in 2012 and continues. Excavation and containment remedies are complete. A long-term groundwater pump and treatment program is now underway. The final design was approved by the EPA in late 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $65 million, of which approximately $47 million has already been spent.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and which remedy will be implemented. The EPA’s ROD 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. NSP-Wisconsin believes the Hybrid Remedy is not safe or feasible to implement. In 2015, NSP-Wisconsin constructed a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. The wet dredge pilot study is anticipated to commence in spring 2016.

As a result of litigation and settlements approved by the U.S. District Court for the Western District of Wisconsin in 2015, three other PRPs have contributed $15.9 million to the remediation of the site. Settlements in principle were also reached with the City of Ashland and the County of Ashland in January 2016, and NSP-Wisconsin anticipates that its litigation efforts against other PRPs are complete.

At Dec. 31, 2015 and 2014, NSP-Wisconsin had recorded a liability of $94.4 million and $107.6 million, respectively, for the Site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $17.0 million and $28.9 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 Site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented and whether federal or state funding may be directed to help offset remediation costs at the Site.

NSP-Wisconsin has deferred the estimated site remediation costs as a regulatory asset. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In a December 2012 decision, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period, and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2015, the PSCW approved NSP-Wisconsin’s 2016 rate case request for an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million.

Other MGP Sites— NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where regulated materials may have been deposited. NSP-Wisconsin has identified one site where former MGP activities may have resulted in site contamination and is under current investigation. At this MGP site, there are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the remediation at this site will continue through at least 2016. NSP-Wisconsin had accrued $0.2 million for this site at Dec. 31, 2015 and 2014, 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 September 2015, the EPA issued a final 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. NSP-Wisconsin has reviewed the final rule and is in the process of evaluating whether the costs of compliance could have a material impact on the results of operations, financial position or cash flows. NSP-Wisconsin believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Section 316(b)— Section 316(b) of 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. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Many of the compliance requirements depend on site-specific determinations by state regulators; therefore, the exact cost is somewhat uncertain. NSP-Wisconsin believes at least two plants could be required by state regulators to make improvements to reduce entrainment. NSP-Wisconsin estimates the likely cost for complying with impingement requirements may be incurred between 2016 and 2027 and is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.

Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In October 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  States must develop implementation plans by September 2016, with the possibility of an extension to September 2018, or the EPA will prepare a federal plan for the state.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.  The CPP is currently being challenged by multiple parties in the D.C. Circuit Court.  In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule as well as ordered expedited review of the CPP, with briefings to be completed and oral arguments held by June 2016.  Following the D.C. Circuit Court’s denial of motions for stay, multiple parties filed requests for stay with the U.S. Supreme Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until, first, the D.C. Circuit Court and then the U.S. Supreme Court have ruled on the challenges to the CPP.

NSP-Wisconsin has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals.  The CPP could require additional emission reductions in states in which NSP-Wisconsin operates.  If state plans do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs.  Until NSP-Wisconsin has more information about SIPs or knows the requirements of the EPA’s upcoming final rule on federal plans for the states that do not develop related plans, NSP-Wisconsin cannot predict the costs of compliance with the final rule once it takes effect.  NSP-Wisconsin believes compliance costs will be recoverable through regulatory mechanisms.  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 CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

CSAPR— CSAPR addresses 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, using an emissions trading program. CSAPR compliance in 2015 did not and 2016 is not expected to have a material impact on the results of operations, financial position or cash flows.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone NAAQS and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. If adopted as proposed, the ozone season emission budget for NOx is not expected to impact NSP-Wisconsin.

Revisions to the NAAQS for Ozone— In October 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. Current monitored air quality concentrations in areas of Wisconsin, where NSP-Wisconsin operates, are below the new standard. Therefore, NSP-Wisconsin does not expect a material impact on results of operations, financial position or cash flows.

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 distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. AROs also have been recorded for NSP-Wisconsin steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.

NSP-Wisconsin has recognized an ARO for the retirement costs of natural gas mains and lines and for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks and office buildings.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. No cash flow revisions were necessary, as a result of the final rule, as of Dec. 31, 2015.

A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow Revisions			Ending Balance    Dec. 31, 2015(a)
Electric plant
Steam production asbestos	$	2,049	$	45	$	51		$	2,145
Steam production ash containment	374		14		229			617
Electric distribution	37		1		34			72
Other	412		15		(36		)	391
Natural gas plant
Gas distribution	6,127		240		—			6,367
Common and other property
Common miscellaneous	91		4		—			95
Total liability (b)	$	9,090	$	319	$	278		$	9,687

^(a)  There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

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

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow    Revisions(a)		Ending Balance     Dec. 31, 2014 (b)
Electric plant
Steam production asbestos	$	2,005	$	—	$	44	$	—	$	2,049
Steam production ash containment	361		—		13		—		374
Electric distribution	36		—		1		—		37
Other	289		113		10		—		412
Natural gas plant
Gas distribution	75		402		5		5,645		6,127
Common and other property
Common miscellaneous	87		—		3		1		91
Total liability (c)	$	2,853	$	515	$	76	$	5,646	$	9,090

^(a)  In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas distribution.

^(b)  There were no ARO liabilities settled during the year ended Dec. 31, 2014.

^(c)  Included in other long-term liabilities balance in the consolidated balance sheet.

Indeterminate AROs— Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Wisconsin’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2015. Therefore, an ARO has not been recorded for these facilities.

Removal Costs— NSP-Wisconsin records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. 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 time periods over which the amounts were accrued and the changing of rates over 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, 2015 and 2014 were $132 million and $123 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.

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy.  e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The cases were consolidated in U.S. District Court in Nevada.  In 2009, five of the cases were settled and one was dismissed.  The U.S. District Court in 2011 issued an order dismissing entirely six of the remaining seven lawsuits, and partially dismissing the seventh. Plaintiffs appealed the dismissals to the Ninth Circuit, which reversed the District Court. The matter was ultimately heard by the U.S. Supreme Court in early 2015, which agreed with the Ninth Circuit and remanded the matter to the U.S. District Court. In September 2015, the District Court held a status conference and set deadlines for certain litigation related activities in 2016. A trial date has not yet been set, but is not expected to occur prior to late 2016 or early 2017. Xcel Energy and e prime have concluded that a loss is remote with respect to this matter.

Other Contingencies

See Note 10 for further discussion.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	6,702	$	160,699	$	4,376	$	147,793
Pension and retiree medical obligations (a)	7	Various	6,415		86,778		6,837		91,601
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		20,586		—		16,711
State commission adjustments	1	Plant lives	724		12,945		488		11,650
Losses on reacquired debt	4	Term of related debt	803		4,134		801		4,936
Deferred income tax adjustment	1, 6	Typically plant lives	—		2,250		—		1,514
Recoverable purchased natural gas and electric energy costs		Less than one year	1,032		—		6,946		—
Monticello EPU		N/A	—		—		—		5,237
Other		Various	470		1,804		588		1,251
Total regulatory assets			$	16,146	$	289,196	$	20,036	$	280,693

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

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	132,311	$	—	$	123,105
Investment tax credit deferrals	1, 6	Various	—		8,869		—		9,397
Deferred electric production and natural gas costs	1	Less than one year	9,386		—		—		—
DOE settlement	11	One to two years	1,996		—		4,931		—
Conservation programs	1	Less than one year	339		—		1,010		—
Excess depreciation reserve		Less than one year	60		—		10,999		—
Other		Various	—		109		—		172
Total regulatory liabilities			$	11,781	$	141,289	$	16,940	$	132,674

At Dec. 31, 2015 and 2014, approximately $1.0 million and $12.1 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes Monticello EPU costs and recoverable purchased natural gas and electric energy costs.

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2015

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2015			Year Ended Dec. 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(285	)	$	(361	)
Losses reclassified from net accumulated other comprehensive loss	76			76
Net current period OCI	76			76
Accumulated other comprehensive loss at Dec. 31	$	(209	)	$	(285	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2015				Year Ended Dec. 31, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	127		(a)	$	127		(a)
Total, pre-tax	127				127
Tax benefit	(51		)		(51		)
Total amounts reclassified, net of tax	$	76			$	76

^(a)  Included in interest charges.

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Segments and Related Information

12 Months Ended

Dec. 31, 2015

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.

• 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
2015
Operating revenues (a)	$	834,998	$	120,147	$	1,396	$	—		$	956,541
Intersegment revenues	419		498		—		(917		)	—
Total revenues	$	835,417	$	120,645	$	1,396	$	(917	)	$	956,541
Depreciation and amortization	$	77,036	$	14,034	$	175	$	—		$	91,245
Interest charges and financing costs	26,494		2,637		90		—			29,221
Income tax expense	40,654		2,501		1,083		—			44,238
Net Income	69,398		4,862		376		—			74,636

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2014
Operating revenues (a)	$	829,748	$	169,629	$	1,085		$	—		$	1,000,462
Intersegment revenues	497		4,885		—			(5,382		)	—
Total revenues	$	830,245	$	174,514	$	1,085		$	(5,382	)	$	1,000,462
Depreciation and amortization	$	65,978	$	13,501	$	175		$	—		$	79,654
Interest charges and financing costs	23,448		2,358		107			—			25,913
Income tax expense (benefit)	39,621		5,993		(3,211		)	—			42,403
Net Income	59,060		8,714		2,868			—			70,642

(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	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

^(a)  Operating revenuesinclude $163 million, $145 million and $137 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013 respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

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)	2015		2014		2013
Operating revenues:
Electric	$	163,255	$	145,102	$	136,917
Operating expenses:
Purchased power (a)	419,028		430,666		416,173
Transmission expense	54,070		43,876		42,460
Natural gas purchased for resale	45		90		97
Other operating expenses — paid to Xcel Energy Services Inc.	93,890		84,224		61,531
Interest expense	2		30		22

^(a)  Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

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

	2015				2014
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	18,268	$	—	$	17,333
PSCo	—		71		—		22
SPS	71		—		31		—
Other subsidiaries of Xcel Energy Inc.	—		6,199		—		9,169
	$	71	$	24,538	$	31	$	26,524

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	273,960	$	216,813	$	236,161	$	229,607
Operating income	39,549		25,069		47,532		27,809
Net income	22,267		12,512		26,232		13,625

	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		Dec. 31, 2014
Operating revenues	$	285,142	$	228,114	$	231,046	$	256,160
Operating income	42,571		23,730		37,540		27,787
Net income	24,235		12,022		20,030		14,355

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2015, 2014 AND 2013

(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:
2015	$	5,821	$	3,947	$	1,161	$	5,801	$	5,128
2014	4,911		4,431		1,269		4,790		5,821
2013	4,333		3,988		1,199		4,609		4,911

^(a)  Recovery of amounts previously written off.

^(b)  Deductions relate primarily to bad debt write-offs.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Business and System of Accounts

Business and System of Accounts— NSP-Wisconsin is 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 has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin's proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin's proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages.

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 or potential disallowances, AROs, certain 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 or OCI, 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 sheets.  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, electric fuel and purchased energy 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. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.

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. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and 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 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 life studies are performed 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 3.4, 3.3 and 3.5 percent for the years ended Dec. 31, 2015, 2014 and 2013, 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. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.

Asset Retirement Obligations

AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. 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. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. 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.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in 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 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 be extended 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 before the related costs are incurred 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, 2015 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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Selected Balance Sheet Data (Tables)

12 Months Ended

Dec. 31, 2015

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Accounts receivable, net (a)
Accounts receivable	$	61,506		$	66,217
Less allowance for bad debts	(5,128		)	(5,821		)
	$	56,378		$	60,396

Inventories

(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,785	$	6,494
Fuel	6,528		6,654
Natural gas	8,246		11,537
	$	21,559	$	24,685

Property, Plant and Equipment, Net

(Thousands of Dollars)	Dec. 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	2,411,562		$	2,061,669
Natural gas plant	275,376			255,465
Common and other property	132,329			125,938
CWIP	65,755			231,413
Total property, plant and equipment	2,885,022			2,674,485
Less accumulated depreciation	(1,056,943		)	(1,000,204		)
	$	1,828,079		$	1,674,281

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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At Dec. 31, 2015, NSP-Wisconsin had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	150	$	10	$	140

^(a)  This credit facility matures in October 2019.

^(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, 2015
Borrowing limit	$	150
Amount outstanding at period end	10
Average amount outstanding	6
Maximum amount outstanding	18
Weighted average interest rate, computed on a daily basis	0.44		%
Weighted average interest rate at period end	0.70

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	10			78			68
Average amount outstanding	39			46			20
Maximum amount outstanding	122			101			71
Weighted average interest rate, computed on a daily basis	0.44		%	0.27		%	0.31		%
Weighted average interest rate at period end	0.70			0.55			0.27

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, 2015			Dec. 31, 2014
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate	0.87		%	0.51		%

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Joint Ownership of Transmission Facilities (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	154,394	$	6,863	$	1,633	80	%
La Crosse, Wis. to Madison, Wis.	—		—		18,894		37
Total NSP-Wisconsin	$	154,394	$	6,863	$	20,527

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.1
Unrecognized tax benefit — Temporary tax positions	4.3		2.9
Total unrecognized tax benefit	$	4.5	$	3.0

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

(Millions of Dollars)	2015			2014			2013
Balance at Jan. 1	$	3.0		$	1.5		$	1.3
Additions based on tax positions related to the current year	1.9			1.9			0.7
Reductions based on tax positions related to the current year	(0.3		)	(0.2		)	—
Additions for tax positions of prior years	0.8			0.1			0.5
Reductions for tax positions of prior years	(0.9		)	(0.2		)	—
Settlements with taxing authorities	—			(0.1		)	(1.0		)
Balance at Dec. 31	$	4.5		$	3.0		$	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, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(0.9	)	$	(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)	2015	2014
Federal NOL carryforward	103	49
Federal tax credit carryforwards	5	5
State NOL carryforward	3	3

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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.8		4.9		5.0
Change in unrecognized tax benefits	0.1		—		—
Tax credits recognized	(0.7	)	(0.7	)	(0.9	)
Regulatory differences — utility plant items	(1.7	)	(1.6	)	(0.9	)
Other, net	(0.3	)	(0.1	)	(0.2	)
Effective income tax rate	37.2	%	37.5	%	38.0	%

Schedule of Components of Income Tax Expense (Benefit)

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

(Thousands of Dollars)	2015			2014			2013
Current federal tax expense (benefit)	$	(4,715	)	$	(3,932	)	$	5,902
Current state tax expense	2,150			453			4,628
Current change in unrecognized tax expense	1,498			1,013			754
Deferred federal tax expense	40,580			38,321			23,794
Deferred state tax expense	6,675			8,042			2,720
Deferred change in unrecognized tax (benefit)	(1,422		)	(967		)	(725		)
Deferred investment tax credits	(528		)	(527		)	(664		)
Total income tax expense	$	44,238		$	42,403		$	36,409

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

(Thousands of Dollars)	2015			2014			2013
Deferred tax expense excluding items below	$	51,084		$	49,793		$	27,516
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(5,200		)	(4,346		)	(1,676		)
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	45,833		$	45,396		$	25,789

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)	2015		2014
Deferred tax liabilities:
Difference between book and tax bases of property	$	382,592	$	319,265
Regulatory assets	78,233		72,670
Employee benefits	18,028		18,691
Other	10,190		14,453
Total deferred tax liabilities	$	489,043	$	425,079
Deferred tax assets:
Environmental remediation	$	37,938	$	43,207
NOL carryforward	37,508		18,283
Regulatory liabilities	9,328		10,460
Deferred investment tax credits	5,312		5,628
Tax credit carryforward	4,760		4,515
Other	3,134		3,007
Total deferred tax assets	$	97,980	$	85,100
Net deferred tax liability	$	391,063	$	339,979

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

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
2016	$	11,278	$	1,443	$	8	$	1,435
2017	11,893		1,324		6		1,318
2018	11,746		1,278		5		1,273
2019	12,920		1,244		4		1,240
2020	13,404		1,203		4		1,199
2021-2025	62,859		5,200		19		5,181

Contributions to Multiemployer Plans

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2015, 2014 and 2013. 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)	2015		2014		2013
Multiemployer plan contributions:
Pension	$	944	$	156	$	130
Total	$	944	$	156	$	130

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 at Dec. 31 for the upcoming year:

	2015		2014
Domestic and international equity securities	41	%	39	%
Long-duration fixed income and interest rate swap securities	23		23
Short-to-intermediate fixed income securities	14		14
Alternative investments	20		22
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, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	6,005	$	—	$	—	$	6,005
Derivatives	—		89		—		89
Government securities	—		13,048		—		13,048
Corporate bonds	—		10,454		—		10,454
Asset-backed securities	—		101		—		101
Common stock	4,213		—		—		4,213
Private equity investments	—		—		5,967		5,967
Commingled funds	—		76,817		—		76,817
Real estate	—		—		2,413		2,413
Other	—		207		—		207
Total	$	10,218	$	100,716	$	8,380	$	119,314

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	7,910	$	—		$	—	$	7,910
Derivatives	—		28			—		28
Government securities	—		16,084			—		16,084
Corporate bonds	—		13,231			—		13,231
Asset-backed securities	—		162			—		162
Mortgage-backed securities	—		475			—		475
Common stock	4,424		—			—		4,424
Private equity investments	—		—			7,078		7,078
Commingled funds	—		81,806			—		81,806
Real estate	—		—			2,510		2,510
Securities lending collateral obligation and other	—		(995		)	—		(995		)
Total	$	12,334	$	110,791		$	9,588	$	132,713

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, 2015, 2014 and 2013:

(Thousands of Dollars)	Jan. 1, 2015		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer Out of Level 3		Dec. 31, 2015
Private equity investments	$	7,078	$	1,326	$	(1,836	)	$	(601	)	$	—	$	5,967
Real estate	2,510		334		(556		)	125			—		2,413
Total	$	9,588	$	1,660	$	(2,392	)	$	(476	)	$	—	$	8,380

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	7,502	$	1,197	$	(1,197	)	$	(424	)	$	—	$	7,078
Real estate	2,299		166		(234		)	279			—		2,510
Total	$	9,801	$	1,363	$	(1,431	)	$	(145	)	$	—	$	9,588

(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	$	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

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)	2015			2014
Accumulated Benefit Obligation at Dec. 31	$	140,917		$	153,590
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	165,669		$	163,930
Service cost	4,759			4,527
Interest cost	6,520			7,257
Actuarial (gain) loss	(11,159		)	9,126
Benefit payments	(13,244		)	(19,171		)
Obligation at Dec. 31	$	152,545		$	165,669

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	132,713		$	136,935
Actual (loss) return on plan assets	(5,087		)	6,916
Employer contributions	4,932			8,033
Benefit payments	(13,244		)	(19,171		)
Fair value of plan assets at Dec. 31	$	119,314		$	132,713

Funded Status of Plans

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(33,231	)	$	(32,956	)

^(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)	2015		2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	86,614	$	90,007
Prior service cost	556		667
Total	$	87,170	$	90,674

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)	2015		2014
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	$	6,300	$	6,728
Noncurrent regulatory assets	80,870		83,946
Total	$	87,170	$	90,674

Schedule of Assumptions Used

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.66	%	4.11	%
Expected average long-term increase in compensation level	4.00		3.75
Mortality table	RP 2014		RP 2014

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.11	%	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75		3.75
Expected average long-term rate of return on assets	7.25		7.25		7.25

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	4,759		$	4,527		$	5,682
Interest cost	6,520			7,257			6,924
Expected return on plan assets	(9,483		)	(9,642		)	(9,995		)
Amortization of prior service cost	111			111			417
Amortization of net loss	6,804			6,617			7,924
Net periodic pension cost	$	8,711		$	8,870		$	10,952

Postretirement Benefit Plan

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:

	2015		2014
Domestic and international equity securities	25	%	25	%
Short-to-intermediate fixed income securities	57		57
Alternative investments	13		13
Cash	5		5
Total	100	%	100	%

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2015 and 2014:

	Dec. 31, 2015
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	18	$	—	$	—	$	18
Government securities	—		37		—		37
Insurance contracts	—		44		—		44
Corporate bonds	—		68		—		68
Asset-backed securities	—		27		—		27
Mortgage-backed securities	—		33		—		33
Commingled funds	—		191		—		191
Total	$	18	$	400	$	—	$	418

	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	28	$	—		$	—	$	28
Government securities	—		52			—		52
Insurance contracts	—		54			—		54
Corporate bonds	—		59			—		59
Asset-backed securities	—		4			—		4
Mortgage-backed securities	—		12			—		12
Commingled funds	—		304			—		304
Other	—		(1		)	—		(1		)
Total	$	28	$	484		$	—	$	512

Changes in Level 3 Plan Assets

For the year ended Dec. 31, 2015 and 2014 there were no assets transferred in or out of Level 3. The following table presents the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the year ended 2013:

(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	)	$	—

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)	2015			2014
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	16,768		$	17,153
Service cost	29			35
Interest cost	653			791
Medicare subsidy reimbursements	13			2
Plan participants’ contributions	130			284
Actuarial gain	(1,645		)	(38		)
Benefit payments	(1,230		)	(1,459		)
Obligation at Dec. 31	$	14,718		$	16,768

Change in Fair Value of Plan Assets

(Thousands of Dollars)	2015			2014
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	512		$	746
Actual loss on plan assets	(12		)	(15		)
Plan participants’ contributions	130			284
Employer contributions	1,018			956
Benefit payments	(1,230		)	(1,459		)
Fair value of plan assets at Dec. 31	$	418		$	512

Funded Status of Plans

(Thousands of Dollars)	2015			2014
Funded Status of Plans at Dec. 31:
Funded status	$	(14,300	)	$	(16,256	)
Current liabilities	(1,017		)	(1,022		)
Noncurrent liabilities	(13,283		)	(15,234		)
Net postretirement amounts recognized on consolidated balance sheets	$	(14,300	)	$	(16,256	)

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(Thousands of Dollars)	2015			2014
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	8,402		$	10,461
Prior service credit	(2,485		)	(2,836		)
Total	$	5,917		$	7,625

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)	2015		2014
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	$	99	$	95
Noncurrent regulatory assets	5,818		7,530
Total	$	5,917	$	7,625

Schedule of Assumptions Used

Measurement date Dec. 31, 2015 Dec. 31, 2014

	2015		2014
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.65	%	4.08	%
Mortality table	RP 2014		RP 2014
Health care costs trend rate — initial	6.00	%	6.50	%

	2015		2014		2013
Significant Assumptions Used to Measure Costs:
Discount rate	4.08	%	4.82	%	4.10	%
Expected average long-term rate of return on assets	5.80		7.08		7.11

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	$	1,420	$	(1,208	)
Service and interest components	77		(65		)

Components of Net Periodic Benefit Costs

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

(Thousands of Dollars)	2015			2014			2013
Service cost	$	29		$	35		$	25
Interest cost	653			791			760
Expected return on plan assets	(30		)	(52		)	(42		)
Amortization of transition obligation	—			—			1
Amortization of prior service credit	(351		)	(351		)	(351		)
Amortization of net loss	456			666			963
Net periodic postretirement benefit cost	$	757		$	1,089		$	1,356

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Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2015

Other Income and Expenses [Abstract]

Other Income, Net

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

(Thousands of Dollars)	2015			2014			2013
Interest income	$	332		$	368		$	538
Other nonoperating income	789			321			152
Insurance policy expense	(228		)	(409		)	(427		)
Other nonoperating expense	(10		)	(10		)	(10		)
Other income, net	$	883		$	270		$	253

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

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:

(Amounts in Thousands)(a)(b)	2015	2014
MMBtu of natural gas	388	18

^(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)	2015			2014			2013
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(285	)	$	(361	)	$	(437	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			76			76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(209	)	$	(285	)	$	(361	)

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, 2015
	Fair Value						Fair Value Total		Counterparty Netting(a)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total(b)
Current derivative assets
Natural gas commodity	$	—	$	15	$	—	$	15	$	(11	)	$	4
Total current derivative assets	$	—	$	15	$	—	$	15	$	(11	)	$	4
Current derivative liabilities
Natural gas commodity	$	—	$	194	$	—	$	194	$	(11	)	$	183
Total current derivative liabilities	$	—	$	194	$	—	$	194	$	(11	)	$	183

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting(a)
(Thousands of Dollars)	Level 1		Level 2		Level 3						Total(c)
Current derivative assets
Natural gas commodity	$	—	$	52	$	—	$	52	$	—	$	52

^(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, 2015 and 2014.  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 $2.4 million and other current liabilities balance of $15.8 million at Dec. 31, 2015 in the consolidated balance sheets.

^(c)  Included in other current assets balance of $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.

Carrying Amount and Fair Value of Long-term Debt

As of Dec. 31, 2015 and 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2015				2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	667,593	$	742,565	$	568,291	$	670,665

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Rate Matters Rate Matters (Tables)

12 Months Ended

Dec. 31, 2015

Public Utilities, General Disclosures [Abstract]

NSP-Wisconsin's 2016 Electric and Gas Rate Case [Table Text Block]

The major components of the requested rate increases and the PSCW's approval are summarized as follows:

Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	23.0		$	13.9
ROE & other capital structure adjustments	—			(3.8		)
Generation and transmission expenses (excluding fuel and purchased power)	37.2			42.7
O&M expenses	11.1			3.2
Sales forecast	(27.0		)	(27.0		)
Rate increase - non-fuel and purchased power	44.3			29.0
Rate reduction - fuel and purchased power	(16.9		)	(21.4		)
Total electric rate increase	$	27.4		$	7.6

Natural Gas Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	3.7		$	3.7
ROE & other capital structure adjustments	—			(0.4		)
O&M expenses	3.2			1.9
Environmental remediation expenses	2.9			2.9
Sales forecast	(3.9		)	(3.9		)
Total natural gas rate increase	$	5.9		$	4.2

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015 are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2016	$	6.7	$	9.7	$	13.1
2017	2.5		0.2		10.4
2018	2.5		—		4.7
2019	0.8		—		3.1
2020	0.8		—		1.9
Thereafter	2.5		—		11.6
Total (a)	$	15.8	$	9.9	$	44.8

^(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)
2016	$	0.9
2017	1.0
2018	0.9
2019	0.9
2020	0.8
Thereafter	7.0
Total	$	11.5

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, 2015		Dec. 31, 2014
Current assets	$	377	$	246
Property, plant and equipment, net	2,199		2,278
Other noncurrent assets	127		122
Total assets	$	2,703	$	2,646
Current liabilities	$	1,246	$	1,349
Mortgages and other long-term debt payable	537		486
Other noncurrent liabilities	51		48
Total liabilities	$	1,834	$	1,883

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
Guarantee of customer loans for the Farm Rewiring Program	$	1.0	$	0.1	2020	(a)

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

Asset Retirement Obligations

A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2015 and 2014 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow Revisions			Ending Balance    Dec. 31, 2015(a)
Electric plant
Steam production asbestos	$	2,049	$	45	$	51		$	2,145
Steam production ash containment	374		14		229			617
Electric distribution	37		1		34			72
Other	412		15		(36		)	391
Natural gas plant
Gas distribution	6,127		240		—			6,367
Common and other property
Common miscellaneous	91		4		—			95
Total liability (b)	$	9,090	$	319	$	278		$	9,687

^(a)  There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

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

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow    Revisions(a)		Ending Balance     Dec. 31, 2014 (b)
Electric plant
Steam production asbestos	$	2,005	$	—	$	44	$	—	$	2,049
Steam production ash containment	361		—		13		—		374
Electric distribution	36		—		1		—		37
Other	289		113		10		—		412
Natural gas plant
Gas distribution	75		402		5		5,645		6,127
Common and other property
Common miscellaneous	87		—		3		1		91
Total liability (c)	$	2,853	$	515	$	76	$	5,646	$	9,090

^(a)  In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas distribution.

^(b)  There were no ARO liabilities settled during the year ended Dec. 31, 2014.

^(c)  Included in other long-term liabilities balance in the consolidated balance sheet.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	6,702	$	160,699	$	4,376	$	147,793
Pension and retiree medical obligations (a)	7	Various	6,415		86,778		6,837		91,601
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		20,586		—		16,711
State commission adjustments	1	Plant lives	724		12,945		488		11,650
Losses on reacquired debt	4	Term of related debt	803		4,134		801		4,936
Deferred income tax adjustment	1, 6	Typically plant lives	—		2,250		—		1,514
Recoverable purchased natural gas and electric energy costs		Less than one year	1,032		—		6,946		—
Monticello EPU		N/A	—		—		—		5,237
Other		Various	470		1,804		588		1,251
Total regulatory assets			$	16,146	$	289,196	$	20,036	$	280,693

^(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, 2015 and 2014 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2015				Dec. 31, 2014
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	132,311	$	—	$	123,105
Investment tax credit deferrals	1, 6	Various	—		8,869		—		9,397
Deferred electric production and natural gas costs	1	Less than one year	9,386		—		—		—
DOE settlement	11	One to two years	1,996		—		4,931		—
Conservation programs	1	Less than one year	339		—		1,010		—
Excess depreciation reserve		Less than one year	60		—		10,999		—
Other		Various	—		109		—		172
Total regulatory liabilities			$	11,781	$	141,289	$	16,940	$	132,674

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2015

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2015			Year Ended Dec. 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(285	)	$	(361	)
Losses reclassified from net accumulated other comprehensive loss	76			76
Net current period OCI	76			76
Accumulated other comprehensive loss at Dec. 31	$	(209	)	$	(285	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2015				Year Ended Dec. 31, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	127		(a)	$	127		(a)
Total, pre-tax	127				127
Tax benefit	(51		)		(51		)
Total amounts reclassified, net of tax	$	76			$	76

^(a)  Included in interest charges.

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2015
Operating revenues (a)	$	834,998	$	120,147	$	1,396	$	—		$	956,541
Intersegment revenues	419		498		—		(917		)	—
Total revenues	$	835,417	$	120,645	$	1,396	$	(917	)	$	956,541
Depreciation and amortization	$	77,036	$	14,034	$	175	$	—		$	91,245
Interest charges and financing costs	26,494		2,637		90		—			29,221
Income tax expense	40,654		2,501		1,083		—			44,238
Net Income	69,398		4,862		376		—			74,636

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2014
Operating revenues (a)	$	829,748	$	169,629	$	1,085		$	—		$	1,000,462
Intersegment revenues	497		4,885		—			(5,382		)	—
Total revenues	$	830,245	$	174,514	$	1,085		$	(5,382	)	$	1,000,462
Depreciation and amortization	$	65,978	$	13,501	$	175		$	—		$	79,654
Interest charges and financing costs	23,448		2,358		107			—			25,913
Income tax expense (benefit)	39,621		5,993		(3,211		)	—			42,403
Net Income	59,060		8,714		2,868			—			70,642

(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	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

^(a)  Operating revenuesinclude $163 million, $145 million and $137 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013 respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

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)	2015		2014		2013
Operating revenues:
Electric	$	163,255	$	145,102	$	136,917
Operating expenses:
Purchased power (a)	419,028		430,666		416,173
Transmission expense	54,070		43,876		42,460
Natural gas purchased for resale	45		90		97
Other operating expenses — paid to Xcel Energy Services Inc.	93,890		84,224		61,531
Interest expense	2		30		22

^(a)  Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

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

	2015				2014
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	18,268	$	—	$	17,333
PSCo	—		71		—		22
SPS	71		—		31		—
Other subsidiaries of Xcel Energy Inc.	—		6,199		—		9,169
	$	71	$	24,538	$	31	$	26,524

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	273,960	$	216,813	$	236,161	$	229,607
Operating income	39,549		25,069		47,532		27,809
Net income	22,267		12,512		26,232		13,625

	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		Dec. 31, 2014
Operating revenues	$	285,142	$	228,114	$	231,046	$	256,160
Operating income	42,571		23,730		37,540		27,787
Net income	24,235		12,022		20,030		14,355

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Percentage of Average Annual Operating Revenues	1.20%
Average Annual Operating Revenues	3 years
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.40%	3.30%	3.50%
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	3 months

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Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable, Net
Accounts receivable		$ 61,506	$ 66,217
Less allowance for bad debts		(5,128)	(5,821)
Accounts receivable, net	[1]	$ 56,378	$ 60,396

[1] Accounts receivable, net includes an immaterial amount due from affiliates for 2015 and 2014, respectively.

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Selected Balance Sheet Data, Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 21,559	$ 24,685
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	6,785	6,494
Fuel
Public Utilities, Inventory [Line Items]
Inventories	6,528	6,654
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 8,246	$ 11,537

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Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 2,885,022	$ 2,674,485
Less accumulated depreciation	(1,056,943)	(1,000,204)
Property, plant and equipment, net	1,828,079	1,674,281
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,411,562	2,061,669
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	275,376	255,465
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	132,329	125,938
CWIP
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 65,755	$ 231,413

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Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Amount outstanding at period end	$ 10,000	$ 10,000	$ 78,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000	150,000	150,000	$ 150,000
Amount outstanding at period end	10,000	10,000	78,000	68,000
Average amount outstanding	6,000	39,000	46,000	20,000
Maximum amount outstanding	$ 18,000	$ 122,000	$ 101,000	$ 71,000
Weighted average interest rate, computed on a daily basis (percentage)	0.44%	0.44%	0.27%	0.31%
Weighted average interest rate at period end (percentage)	0.70%	0.70%	0.55%	0.27%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 10,000	$ 78,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

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Borrowings and Other Financing Instruments, Credit Facility (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Debt To Total Capitalization Ratio		46.00%	48.00%
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
Direct advances on the credit facility outstanding		$ 0	$ 0
Credit Facility
Line of Credit Facility [Line Items]
Debt Instrument, Term		5 years
Credit Facility		$ 150,000,000
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
Drawn	[1]	$ 10,000,000
Available		$ 140,000,000
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%
Eurodollar | Credit Facility
Line of Credit Facility [Line Items]
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%

[1] Includes outstanding commercial paper.

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Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangements and Other Short-Term Borrowings (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Notes Payable, Other Payables
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Weighted average interest rate at period end (percentage)	0.87%	0.51%

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net	$ 5,100,000	$ 4,300,000
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	$ 33,300,000
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%
Calendar year average equity to total capitalization ratio	52.60%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 2,400,000
First Mortgage Bonds | Series Due June 15, 2024
Debt Instrument [Line Items]
Face Amount		$ 100,000,000
Interest Rate, Stated Percentage	3.30%	3.30%
Maturity Date	Jun. 15, 2024	Jun. 15, 2024
First Mortgage Bonds | Series Due Oct. 1, 2018
Debt Instrument [Line Items]
Interest Rate, Stated Percentage	5.25%	5.25%
Maturity Date	Oct. 01, 2018	Oct. 01, 2018
Long-term Debt, Maturities, Repayments of Principal in Year Four	$ 150,000,000
NSP-Wisconsin | First Mortgage Bonds | Series Due June 15, 2024
Debt Instrument [Line Items]
Face Amount	$ 100,000,000
Interest Rate, Stated Percentage	3.30%
Maturity Date	Jun. 15, 2024

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Joint Ownership of Transmission Facilities (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 154,394
Accumulated depreciation	6,863
Construction work in progress	20,527
CapX2020 Transmission | Electric Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	154,394
Accumulated depreciation	6,863
Construction work in progress	$ 1,633
Ownership % (in hundredths)	80.00%
La Crosse, Wis. to Madison, Wis. | Electric Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 0
Accumulated depreciation	0
Construction work in progress	$ 18,894
Ownership % (in hundredths)	37.00%

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Income Taxes (Details)	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2015 USD ($) $ / kWh	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay	2 years
Tax Increase Prevention Act of 2014 [Abstract]
Number of years bonus depreciation was extended		1 year	1 year
American Taxpayer Relief Act of 2012 [Abstract]
Original top tax rate for dividends							15.00%
New top tax rate for dividends							20.00%
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions					$ 200,000	$ 100,000
Unrecognized tax benefit — Temporary tax positions					4,300,000	2,900,000
Total unrecognized tax benefit	$ 3,000,000	$ 1,500,000	$ 1,300,000	$ 1,300,000	4,500,000	3,000,000	$ 1,500,000	$ 1,300,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1	3,000,000	1,500,000	1,300,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	1,900,000	1,900,000	700,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	(300,000)	(200,000)	0
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions	800,000	100,000	500,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions	(900,000)	(200,000)	0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	0	(100,000)	(1,000,000)
Balance at Dec. 31	$ 4,500,000	$ 3,000,000	$ 1,500,000	$ 1,300,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards					(900,000)	(900,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible					2,000,000
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	4.80%	4.90%	5.00%
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent	0.10%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	(0.70%)	(0.70%)	(0.90%)
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent	(1.70%)	(1.60%)	(0.90%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent	(0.30%)	(0.10%)	(0.20%)
Effective Income Tax Rate Reconciliation, Percent	37.20%	37.50%	38.00%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ (4,715,000)	$ (3,932,000)	$ 5,902,000
Current State and Local Tax Expense (Benefit)	2,150,000	453,000	4,628,000
Current Change In Unrecognized Tax Expense (Benefit)	1,498,000	1,013,000	754,000
Deferred Federal Income Tax Expense (Benefit)	40,580,000	38,321,000	23,794,000
Deferred State and Local Income Tax Expense (Benefit)	6,675,000	8,042,000	2,720,000
Deferred Change In Unrecognized Tax Expense (Benefit)	(1,422,000)	(967,000)	(725,000)
Deferred investment tax credits	(528,000)	(527,000)	(664,000)
Income Tax Expense (Benefit)	44,238,000	42,403,000	36,409,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items	51,084,000	49,793,000	27,516,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(5,200,000)	(4,346,000)	(1,676,000)
Other Comprehensive Income (Loss), Tax	(51,000)	(51,000)	(51,000)
Deferred Income Tax Expense (Benefit)	$ 45,833,000	$ 45,396,000	$ 25,789,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment					382,592,000	319,265,000
Deferred Tax Liabilities, Regulatory Assets					78,233,000	72,670,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits					18,028,000	18,691,000
Deferred Tax Liabilities, Other					10,190,000	14,453,000
Deferred Tax Liabilities, Gross					489,043,000	425,079,000
Deferred Tax Liabilities, Net					391,063,000	339,979,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Environmental Remediation					37,938,000	43,207,000
Deferred Tax Assets, Operating Loss Carryforwards					37,508,000	18,283,000
Deferred Tax Assets Regulatory Liabilities					9,328,000	10,460,000
Deferred Tax Assets Deferred Investment Tax Credits					5,312,000	5,628,000
Deferred Tax Assets Tax credit carryforward					4,760,000	4,515,000
Deferred Tax Assets, Other					3,134,000	3,007,000
Deferred Tax Assets, Net of Valuation Allowance					97,980,000	85,100,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination	2012 and 2013			2010 and 2011
Year of carryback claim under examination	2009
Tax Adjustments, Settlements, and Unusual Provisions	$ 14,000,000
Operating Loss Carryforwards					103,000,000	49,000,000
Tax Credit Carryforward, Amount					5,000,000	5,000,000
Carryforward expiration date range, low	2021
Carryforward expiration date range, high	2035
State and Local Jurisdiction
Tax Audits [Abstract]
Earliest year subject to examination	2011
Operating Loss Carryforwards					$ 3,000,000	$ 3,000,000
Carryforward expiration date range, low	2027
Carryforward expiration date range, high	2031
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					50.00%
Consolidated Appropriations Act of 2016; 2018 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					40.00%
Production Tax Credit Rate, Percent					60.00%
Consolidated Appropriations Act of 2016; 2019 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					30.00%
Production Tax Credit Rate, Percent					40.00%
Investment Tax Credit Rate, Percent					30.00%
Consolidated Appropriations Act of 2016; 2016 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent					100.00%
Production Tax Credit per KWh | $ / kWh					0.023
Consolidated Appropriations Act of 2016; 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent					80.00%
Consolidated Appropriations Act of 2016; 2020 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent					26.00%
Consolidated Appropriations Act of 2016; 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent					22.00%
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent					10.00%
Tax Increase Prevention Act of 2014; 2014 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent						50.00%
Tax Increase Prevention Act of 2014; 2015 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent					50.00%
American Taxpayer Relief Act of 2012; 2013 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent							50.00%
American Taxpayer Relief Act of 2012; 2014 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent						50.00%

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Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2015 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 (as a percent)	71.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	400

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Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2015
Commingled funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	1 day
Commingled funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	45 days
Real estate funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

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Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 700	$ 800
Net benefit cost recognized for financial reporting		9,500	4,700
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Total contributions to Xcel Energy's pension plans during the period		4,900	8,000	$ 11,300
Pension Benefits [Abstract]
Total benefit obligation		152,545	165,669	163,930
Net benefit cost recognized for financial reporting		$ 8,711	$ 8,870	$ 10,952
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 (as a percent)		7.25%	7.25%	7.25%
Expected average long-term rate of return on assets for next fiscal year (as a percent)		7.10%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		100.00%	100.00%
Pension Plans | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		41.00%	39.00%
Pension Plans | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		23.00%	23.00%
Pension Plans | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		14.00%	14.00%
Pension Plans | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		20.00%	22.00%
Pension Plans | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		2.00%	2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 41,800	$ 46,500
Xcel Energy Inc. | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Total contributions to Xcel Energy's pension plans during the period		$ 90,100	$ 130,600	$ 192,400
Subsequent Event | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Total contributions to Xcel Energy's pension plans during the period	$ 7,400
Subsequent Event | Xcel Energy Inc. | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Total contributions to Xcel Energy's pension plans during the period	$ 125,000

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Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 119,314	$ 132,713	$ 136,935
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	10,218	12,334
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	100,716	110,791
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	8,380	9,588	9,801	$ 14,894
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	6,005	7,910
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	6,005	7,910
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	89	28
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	89	28
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	13,048	16,084
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	13,048	16,084
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	10,454	13,231
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	10,454	13,231
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	101	162
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	101	162
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	0	0	749
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		475
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
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		475
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	0	2,128
Common stock
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,213	4,424
Common stock | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,213	4,424
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	5,967	7,078
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	5,967	7,078	7,502	8,545
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	76,817	81,806
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	76,817	81,806
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	2,413	2,510
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	2,413	2,510	$ 2,299	$ 3,472
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	207	(995)
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	207	(995)
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

Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 132,713	$ 136,935
Fair value of plan assets at Dec. 31		119,314	132,713	$ 136,935
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		9,588	9,801	14,894
Net realized gains (losses)		1,660	1,363	954
Net unrealized gains (losses)		(2,392)	(1,431)	(1,713)
Purchases, issuances and settlements, net		(476)	(145)	284
Transfers in (out) of Level 3		0	0	(4,618)	[1]
Fair value of plan assets at Dec. 31		8,380	9,588	9,801
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		162
Fair value of plan assets at Dec. 31		101	162
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	749
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(749)
Fair value of plan assets at Dec. 31		0	0	0
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		475
Fair value of plan assets at Dec. 31			475
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	2,128
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(2,128)
Fair value of plan assets at Dec. 31			0	0
Private equity investments
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		7,078
Fair value of plan assets at Dec. 31		5,967	7,078
Private equity investments | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		7,078	7,502	8,545
Net realized gains (losses)		1,326	1,197	1,083
Net unrealized gains (losses)		(1,836)	(1,197)	(1,960)
Purchases, issuances and settlements, net		(601)	(424)	(166)
Transfers in (out) of Level 3		0	0	0	[1]
Fair value of plan assets at Dec. 31		5,967	7,078	7,502
Real estate
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		2,510
Fair value of plan assets at Dec. 31		2,413	2,510
Real estate | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		2,510	2,299	3,472
Net realized gains (losses)		334	166	(129)
Net unrealized gains (losses)		(556)	(234)	247
Purchases, issuances and settlements, net		125	279	450
Transfers in (out) of Level 3		0	0	(1,741)	[1]
Fair value of plan assets at Dec. 31		$ 2,413	$ 2,510	$ 2,299

[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, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Thousands		1 Months Ended	12 Months Ended
		Jan. 31, 2016 USD ($) Plan	Dec. 31, 2015 USD ($) Plan	Dec. 31, 2014 USD ($) Plan	Dec. 31, 2013 USD ($) Plan
Significant Assumptions Used to Measure Costs [Abstract]
Contributions to 401(k) and other defined contribution plans			$ 1,400	$ 1,400	$ 1,300
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			140,917	153,590
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 152,545	165,669	163,930
Service cost			4,759	4,527	5,682
Interest cost			6,520	7,257	6,924
Actuarial (gain) loss			(11,159)	9,126
Benefit payments			(13,244)	(19,171)
Obligation at Dec. 31			152,545	165,669	163,930
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		119,314	132,713	136,935
Actual return (loss) on plan assets			(5,087)	6,916
Employer contributions			4,932	8,033
Benefit payments			(13,244)	(19,171)
Fair value of plan assets at Dec. 31			119,314	132,713	136,935
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]		(33,231)	(32,956)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			86,614	90,007
Prior service (credit) cost			556	667
Total			87,170	90,674
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			6,300	6,728
Noncurrent regulatory assets			80,870	83,946
Total			$ 87,170	$ 90,674
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date			December 31, 2015	December 31, 2014
Discount rate for year-end valuation (as a percent)			4.66%	4.11%
Expected average long-term increase in compensation level (as a percent)			4.00%	3.75%
Mortality table			RP 2014	RP 2014
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 4,900	$ 8,000	11,300
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			4,759	4,527	5,682
Interest cost			6,520	7,257	6,924
Expected return on plan assets			(9,483)	(9,642)	(9,995)
Amortization of prior service cost (credit)			111	111	417
Amortization of net loss			6,804	6,617	7,924
Net periodic benefit cost			$ 8,711	$ 8,870	$ 10,952
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.11%	4.75%	4.00%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%	3.75%
Expected average long-term rate of return on assets (as a percent)			7.25%	7.25%	7.25%
Allocated costs for pension plans sponsored by Xcel Energy Inc.			$ 1,900	$ 1,700	$ 2,200
Expected average long-term rate of return on assets for next fiscal year (as a percent)			7.10%
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 (as a percent)			20.00%
Xcel Energy Inc. | Pension Plans
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 90,100	$ 130,600	$ 192,400
Number of pension plans to which contributions were made | Plan			4	4	4
Subsequent Event | Pension Plans
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		7,400
Subsequent Event | Xcel Energy Inc. | Pension Plans
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 125,000
Number of pension plans to which contributions were made | Plan		4

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

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Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 1.4	$ 1.4	$ 1.3

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefit Plan	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	25.00%	25.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	57.00%	57.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	5.00%	5.00%

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Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 418	$ 512	$ 746
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	18	28
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	400	484
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0	0	$ 55
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	18	28
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	18	28
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
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	37	52
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	37	52
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	44	54
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	44	54
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	68	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	68	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	27	4
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	27	4
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	0	0	1
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	33	12
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	33	12
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	0	$ 0	$ 54
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	191	304
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	191	304
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		(1)
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		(1)
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 0

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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		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 512	$ 746
Fair value of plan assets at Dec. 31		418	512	$ 746
Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	55
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(55)
Fair value of plan assets at Dec. 31		0	0	0
Asset-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		4
Fair value of plan assets at Dec. 31		27	4
Asset-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	1
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(1)
Fair value of plan assets at Dec. 31		0	0	0
Mortgage-backed securities
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		12
Fair value of plan assets at Dec. 31		33	12
Mortgage-backed securities | Level 3
Changes in Level 3 Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		0	0	54
Net realized gains (losses)				0
Net unrealized gains (losses)				0
Purchases, issuances and settlements, net				0
Transfers in (out) of Level 3	[1]			(54)
Fair value of plan assets at Dec. 31		$ 0	$ 0	$ 0

[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, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities	$ (49,889)	$ (51,313)
Postretirement Benefit Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	16,768	17,153
Service cost	29	35	$ 25
Interest cost	653	791	760
Medicare subsidy reimbursements	13	2
Plan participants' contributions	130	284
Actuarial (gain) loss	(1,645)	(38)
Benefit payments	(1,230)	(1,459)
Obligation at Dec. 31	14,718	16,768	17,153
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	512	746
Actual return (loss) on plan assets	(12)	(15)
Plan participants' contributions	130	284
Employer contributions	1,018	956
Benefit payments	(1,230)	(1,459)
Fair value of plan assets at Dec. 31	418	512	746
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(14,300)	(16,256)
Current liabilities	(1,017)	(1,022)
Noncurrent liabilities	(13,283)	(15,234)
Net postretirement amounts recognized on consolidated balance sheets	(14,300)	(16,256)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	8,402	10,461
Prior service (credit) cost	(2,485)	(2,836)
Total	5,917	7,625
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	99	95
Noncurrent regulatory assets	5,818	7,530
Total	$ 5,917	$ 7,625
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Measurement date	12/31/2015	12/31/2014
Discount rate for year-end valuation (as a percent)	4.65%	4.08%
Mortality table	RP 2014	RP 2014
Health care costs trend rate - initial (as a percent)	6.00%	6.50%
Ultimate health care trend assumption rate (as a percent)	4.50%
Period until ultimate trend rate is reached (in years)	3 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO	$ 1,420
One-percent decrease in APBO	(1,208)
One-percent increase in service and interest components	77
One-percent decrease in service and interest components	(65)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	1,000	$ 1,000	1,500
Expected contribution to postretirement health care plans during 2015	1,400
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	29	35	25
Interest cost	653	791	760
Expected return on plan assets	(30)	(52)	(42)
Amortization of transition obligation	0	0	1
Amortization of prior service cost (credit)	(351)	(351)	(351)
Amortization of net loss	456	666	963
Net periodic benefit cost	$ 757	$ 1,089	$ 1,356
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	4.08%	4.82%	4.10%
Expected average long-term rate of return on assets (as a percent)	5.80%	7.08%	7.11%
Xcel Energy Inc. | Postretirement Benefit Plan
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	$ 18,300	$ 17,100	$ 17,600
Expected contribution to postretirement health care plans during 2015	$ 12,300

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Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Pension Plans
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2016	$ 11,278
2017	11,893
2018	11,746
2019	12,920
2020	13,404
2021-2025	62,859
Postretirement Benefit Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2016	1,443
2017	1,324
2018	1,278
2019	1,244
2020	1,203
2021-2025	5,200
Expected Medicare Part D Subsidies [Abstract]
2016	8
2017	6
2018	5
2019	4
2020	4
2021-2025	19
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2016	1,435
2017	1,318
2018	1,273
2019	1,240
2020	1,199
2021-2025	$ 5,181

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Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) Employer	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
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 | Employer	1
Multiemployer contributions	$ 944	$ 156	$ 130
Multiemployer Pension Plans
Multiemployer Plans [Abstract]
Multiemployer contributions	$ 944	$ 156	$ 130

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Other Income, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Income and Expenses [Abstract]
Interest income	$ 332	$ 368	$ 538
Other nonoperating income	789	321	152
Insurance Policy Expense (Income), Net	(228)	(409)	(427)
Other nonoperating expense	(10)	(10)	(10)
Other income, net	$ 883	$ 270	$ 253

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MMBTU in Thousands, $ in Millions	Dec. 31, 2015 USD ($) MMBTU	Dec. 31, 2014 MMBTU
Natural Gas Commodity
Gross Notional Amounts of Commodity Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	388	18
Interest Rate Swap
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)

XML

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ (285)	$ (361)	$ (437)
After-tax net realized losses on derivative transactions reclassified into earnings	76	76	76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (209)	$ (285)	$ (361)

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive 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)
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	(700,000)	$ 100,000	(100,000)
Derivative Instruments Gain Loss Reclassified To Regulatory Assets And Liabilities Net	$ (1,400,000)		$ (700,000)

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2015		Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Prepayments and other		$ 2,387		$ 6,918
Other current liabilities		15,778		12,265
Fair Value Measured on a Recurring Basis | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	4
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		4	[1]	52	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	183
Fair Value Measured on a Recurring Basis | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[1]	183
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15		52
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		194
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		194
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Fair Value Total
Derivatives, Fair Value [Line Items]
Prepayments and other		2,400
Other current liabilities		15,800		6,900
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15		52
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		194
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		194
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[3]	(11)
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[3]	(11)		$ 0
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[3]	(11)
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities [Member] | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[3]	$ (11)

[1] Included in other current assets balance of $2.4 million and other current liabilities balance of $15.8 million at Dec. 31, 2015 in the consolidated balance sheets.

[2] Included in other current assets balance of $6.9 million at Dec. 31, 2014 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, 2015 and 2014. 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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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 667,593	$ 568,291
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 742,565	$ 670,665

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Rate Matters (Details) $ in Thousands		1 Months Ended						3 Months Ended	12 Months Ended
	Jan. 06, 2015	Jan. 31, 2016	Dec. 31, 2015 USD ($)	May. 31, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015	Nov. 30, 2013	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2008 USD ($)
Public Utilities, General Disclosures [Line Items]
Loss on Monticello LCM/EPU project									$ 5,237	$ 0	$ 0
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 5,900
Public Utilities, Requested Rate Increase (Decrease), Percentage				5.00%
Public Utilities, Requested Rate Base, Amount				$ 111,200
Public Utilities, Percentage of Requested Non-fuel and Purchased Power Rate Increase Approved by Commission			71.00%
Public utilities, Requested Increase Related To Capital Investment				3,700
Public Utilities, Requested Decrease Related to ROE and Capital Structure				0
Public Utilities, Requested Increase Related to Operating and Maintenance Expenses				3,200
Public Utilities, Requested Decrease Related to Sales Forecast				(3,900)
Public Utilities, Requested Increase Related Environmental Remediation Expenses				$ 2,900
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | Public Service Commission of Wisconsin (PSCW) [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 4,200
Public Utilities, Approved Rate Increase (Decrease), Percentage			3.60%
Public utilities, Approved Increase Related To Capital Investment			$ 3,700
Public Utilities, Approved Decrease Related to ROE and Capital Structure			(400)
Public Utilities, Approved Increase Related to Operating and Maintenance Expenses			1,900
Public Utilities, Approved Decrease Related to Sales Forecast			3,900
Public Utilities, Approved Increase Related Environmental Remediation Expenses			$ 2,900
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Return on Equity, Percentage				10.20%
Public Utilities, Requested Equity Capital Structure, Percentage				52.50%
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage			10.00%
Public Utilities, Approved Equity Capital Structure, Percentage			52.50%
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 27,400
Public Utilities, Requested Rate Increase (Decrease), Percentage				3.90%
Public Utilities, Requested Rate Base, Amount				$ 1,200,000
Public Utilities, Percentage of Requested Non-fuel and Purchased Power Rate Increase Approved by Commission			65.00%
Public utilities, Requested Increase Related To Capital Investment				23,000
Public Utilities, Requested Decrease Related to ROE and Capital Structure				0
Public Utilities, Requested Increase Related to Generation and Transmission Expenses				37,200
Public Utilities, Requested Increase Related to Operating and Maintenance Expenses				11,100
Public Utilities, Requested Decrease Related to Sales Forecast				(27,000)
Public Utilities, Total Requested Rate Increase Excluding Fuel and Purchased Power				44,300
Public Utilities, Requested Decrease Related to Fuel and Purchased Power Expenses				$ (16,900)
NSP-Wisconsin | PSCW Proceeding - Electric and Gas Rate Case 2016 - Electric Rates 2016 [Member] | Public Service Commission of Wisconsin (PSCW) [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 7,600
Public Utilities, Approved Rate Increase (Decrease), Percentage			1.10%
Public utilities, Approved Increase Related To Capital Investment			$ 13,900
Public Utilities, Approved Decrease Related to ROE and Capital Structure			(3,800)
Public Utilities, Approved Increase Related to Operating and Maintenance Expenses			42,700
Public Utilities, Approved Increase Related to Operating and Maintenance Expenses			3,200
Public Utilities, Approved Decrease Related to Sales Forecast			27,000
Public Utilities, Total Approved Rate Increase Excluding Fuel and Purchased Power			29,000
Public Utilities, Approved Decrease Related to Fuel and Purchased Power Expenses			$ 21,400
NSP-Wisconsin | Nuclear Project Prudency Investigation [Member]
Public Utilities, General Disclosures [Line Items]
Loss on Monticello LCM/EPU project								$ 5,000
NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, upper bound, percentage							12.38%
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties						8.67%	9.15%
Public Utilities, maximum equity capital structure percentage allowed per the complaint							50.00%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Lower Bound, Percentage									8.67%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Upper Bound, Percentage									9.54%
NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member] | Federal Energy Regulatory Commission (FERC) [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, number of steps required for newly adopted ROE discounted cash flow methodology									2
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties	50
NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member] | FERC Staff [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties									8.68%
NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member] | MISO TOs [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Lower Bound, Percentage									10.80%
NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member] | Administrative Law Judge [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties			10.32%
NSP-Minnesota | Nuclear Project Prudency Investigation [Member]
Public Utilities, General Disclosures [Line Items]
Nuclear Project Expenditures, Amount											665,000
Total Capitalized Nuclear Project Costs											$ 748,000
Initial Estimated Nuclear Project Expenditures												$ 320,000
NSP-Minnesota | Nuclear Project Prudency Investigation [Member] | Minnesota Public Utilities Commission [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Amount Of Recoverable Investment, With Return					$ 415,000
Public Utilities, Amount Of Recoverable Investment, Without A Return					$ 333,000
Public Utilities, Percentage Of Investment Considered Used And Useful					50.00%
Xcel Energy Inc. | Nuclear Project Prudency Investigation [Member]
Public Utilities, General Disclosures [Line Items]
Loss on Monticello LCM/EPU project								$ 129,000
Minimum | NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology									$ 8,000
Minimum | NSP-Minnesota | Nuclear Project Prudency Investigation [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Facility Generating Capacity, In MW | MW									600
Maximum | NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Decrease In Transmission Revenue, Net Of Expense, Due To New ROE Methodology									$ 10,000
Maximum | NSP-Minnesota | Nuclear Project Prudency Investigation [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Facility Generating Capacity, In MW | MW									671
Subsequent Event | NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Lower Bound, Percentage		8.72%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Upper Bound, Percentage		9.32%
Subsequent Event | NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member] | FERC Staff [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties		8.78%
Subsequent Event | NSP-Wisconsin | FERC Proceeding, MISO ROE Complaint [Member] | MISO TOs [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties		10.96%

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Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs (in hundredths)	2.00%
Coal
Fuel Contracts [Abstract]
2016	$ 6.7
2017	2.5
2018	2.5
2019	0.8
2020	0.8
Thereafter	2.5
Total	15.8	[1]
Natural Gas Supply
Fuel Contracts [Abstract]
2016	9.7
2017	0.2
2018	0.0
2019	0.0
2020	0.0
Thereafter	0.0
Total	9.9	[1]
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2016	13.1
2017	10.4
2018	4.7
2019	3.1
2020	1.9
Thereafter	11.6
Total	$ 44.8	[1]
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date (year)	2016
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date (year)	2029

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

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Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Leases [Abstract]
Total expenses under operating lease obligations	$ 1.1	$ 1.3	$ 1.4
Office Space and Other Equipment
Operating Leases, Future Minimum Payments Due [Abstract]
2016	0.9
2017	1.0
2018	0.9
2019	0.9
2020	0.8
Thereafter	7.0
Total	$ 11.5

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Commitments and Contingencies, Variable Interest Entities (Details) - Low-Income Housing Limited Partnerships - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Amounts Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 377	$ 246
Property, plant and equipment, net	2,199	2,278
Other noncurrent assets	127	122
Total assets	2,703	2,646
Current liabilities	1,246	1,349
Mortgages and other long-term debt payable	537	486
Other noncurrent liabilities	51	48
Total liabilities	$ 1,834	$ 1,883

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Commitments and Contingencies, Joint Operating System (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) Plant Reactor Counterparty
Joint Operating System [Abstract]
Number of companies covered by FERC approved Interchange Agreement | Counterparty	2
NSP-Minnesota | Nuclear Insurance
Joint Operating System [Abstract]
Maximum possible loss contingency	$ 13,500.0
Nuclear insurance coverage secured for the Company's public liability exposure	375.0
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,100.0
Maximum assessments per reactor per accident	$ 127.3
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 19.0
Term for maximum installment payment assessment per reactor (in years)	1 year
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	$ 2,300.0
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 19.9
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	$ 43.7

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Commitments and Contingencies, Guarantees (Details) - Payment or Performance Guarantee - Customer Loans for Farm Rewiring Program $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Guarantee [Abstract]
Assets held as collateral	$ 0.0
Guarantees issued and outstanding	1.0	[1]
Current exposure under these guarantees	$ 0.1	[1]
Guarantee Expiration Date (year)	2020	[1]

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

XML

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($) Site	Dec. 31, 2015 USD ($) Site	Dec. 31, 2014 USD ($)
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites, current	$ 17,155	$ 17,155	$ 29,116
Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties included in superfund site which NSP-Wisconsin does not own | Site	2	2
Liability for estimated cost of remediating sites, current	$ 17,000	$ 17,000	28,900
Accrual for Environmental Loss Contingencies, Gross	94,400	$ 94,400	107,600
Public Utilities, Annual recovery collected through base rates			4,700
Ashland MGP Site - Phase I Project Area
Manufactured Gas Plant (MGP) Site [Abstract]
Approved amortization period for recovery of remediation costs in natural gas rates (in years)		10 years
Accrual for Environmental Loss Contingencies, Gross	65,000	$ 65,000
Estimated amount spent on cleanup	47,000	$ 47,000
Carrying cost percentage to be applied to unamortized regulatory asset		3.00%
Ashland MGP Site - Sediments
Manufactured Gas Plant (MGP) Site [Abstract]
Estimated cost of remediating site, low end of range	63,000	$ 63,000
Estimated cost of remediating site, high end of range	$ 77,000	$ 77,000
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)	50.00%	50.00%
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)	30.00%	30.00%
Other MGP Sites
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites	$ 200	$ 200	$ 200
Number of identified MGP sites under current investigation and/or remediation | Site	1	1
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Approved annual recovery collected through base rates	$ 7,600
Other PRPs | NSP-Wisconsin | Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Number of PRPs that have contributed to remediation site		3
Contributions to site cleanup by PRPs		$ 15,900

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Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	Dec. 31, 2015 USD ($)	Oct. 30, 2015 Period
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of hours measured for standard | Period		8
Current level of air quality concentrations (in parts per billion)		75
Proposed level of air quality concentrations (in parts per billion)		70
Capital Commitments | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Liability for estimated cost to comply with entrainment regulation | $	$ 4

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Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	[1]	$ 9,090	[2]	$ 2,853
Liabilities recognized		0		515
Liabilities settled		0		0
Accretion		319		76
Cash Flow Revisions		278		5,646	[3]
Ending balance		9,687	[4],[5]	9,090	[1],[2]
Electric Plant Steam Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		2,049	[2]	2,005
Liabilities recognized		0		0
Liabilities settled		0		0
Accretion		45		44
Cash Flow Revisions		51		0	[3]
Ending balance		2,145	[5]	2,049	[2]
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		374	[2]	361
Liabilities recognized		0		0
Liabilities settled		0		0
Accretion		14		13
Cash Flow Revisions		229		0	[3]
Ending balance		617	[5]	374	[2]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		37	[2]	36
Liabilities recognized		0		0
Liabilities settled		0		0
Accretion		1		1
Cash Flow Revisions		34		0	[3]
Ending balance		72	[5]	37	[2]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		412	[2]	289
Liabilities recognized		0		113
Liabilities settled		0		0
Accretion		15		10
Cash Flow Revisions		(36)		0	[3]
Ending balance		391	[5]	412	[2]
Natural Gas Plant Gas Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		6,127	[2]	75
Liabilities recognized		0		402
Liabilities settled		0		0
Accretion		240		5
Cash Flow Revisions		0		5,645	[3]
Ending balance		6,367	[5]	6,127	[2]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		91	[2]	87
Liabilities recognized		0		0
Liabilities settled		0		0
Accretion		4		3
Cash Flow Revisions		0		1	[3]
Ending balance		$ 95	[5]	$ 91	[2]

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

[2] There were no ARO liabilities settled during the year ended Dec. 31, 2014.

[3] In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas distribution.

[4] Included in other long-term liabilities balance in the consolidated balance sheet.

[5] There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

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Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 132	$ 123

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Commitments and Contingencies, Legal Contingencies (Details) - Gas Trading Litigation [Member]	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2009
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	7	13
Loss Contingency, Claims Settled, Number		5
Loss Contingency, Claims Dismissed, Number	6	1
NSP-Wisconsin
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number		2

XML

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 16,146	$ 20,036
Regulatory Asset, Noncurrent		289,196	280,693
Past expenditures not currently earning a return		$ 1,000	12,100
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 6,702	4,376
Regulatory Asset, Noncurrent		$ 160,699	147,793
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current	[1]	$ 6,415	6,837
Regulatory Asset, Noncurrent	[1]	$ 86,778	91,601
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 20,586	16,711
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related debt
Regulatory Asset, Current		$ 803	801
Regulatory Asset, Noncurrent		$ 4,134	4,936
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 724	488
Regulatory Asset, Noncurrent		$ 12,945	11,650
Deferred Income Tax Adjustment
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Typically plant lives
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 2,250	1,514
Recoverable Purchased Natural Gas And Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Less than one year
Regulatory Asset, Current		$ 1,032	6,946
Regulatory Asset, Noncurrent		$ 0	0
Monticello EPU Cost Deferral
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		N/A
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 0	5,237
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 470	588
Regulatory Asset, Noncurrent		$ 1,804	$ 1,251

[1] Includes the non-qualified pension plan.

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 11,781	$ 16,940
Regulatory Liability, Noncurrent	141,289	132,674
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	$ 132,311	123,105
Regulatory liability, remaining amortization period	Plant lives
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 1,996	4,931
Regulatory Liability, Noncurrent	$ 0	0
Regulatory liability, remaining amortization period	One to two years
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 0	0
Regulatory Liability, Noncurrent	$ 8,869	9,397
Regulatory liability, remaining amortization period	Various
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 339	1,010
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	$ 9,386	0
Regulatory Liability, Noncurrent	$ 0	0
Regulatory liability, remaining amortization period	Less than one year
Excess depreciation reserve
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 60	10,999
Regulatory Liability, Noncurrent	$ 0	0
Regulatory liability, remaining amortization period	Less than one year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 0	0
Regulatory Liability, Noncurrent	$ 109	$ 172
Regulatory liability, remaining amortization period	Various

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Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		$ (285)
Accumulated other comprehensive income (loss) at end of period		(209)	$ (285)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(118,874)	(113,045)	$ (95,877)
Income tax expense (benefit)		44,238	42,403	36,409
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		(285)	(361)
(Gains) losses reclassified from net accumulated other comprehensive loss		76	76
Net current period other comprehensive income (loss)		76	76
Accumulated other comprehensive income (loss) at end of period		(209)	(285)	$ (361)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		127	127
Income tax expense (benefit)		(51)	(51)
Total, net of tax		76	76
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	$ 127	$ 127

[1] Included in interest charges.

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Segments and Related Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Intercompany Revenue										$ 163,000	$ 145,000	$ 137,000
Operating revenues		$ 229,607	$ 236,161	$ 216,813	$ 273,960	$ 256,160	$ 231,046	$ 228,114	$ 285,142	956,541	1,000,462	923,038
Depreciation and amortization										91,245	79,654	76,897
Total interest charges and financing costs										29,221	25,913	25,816
Income tax expense (benefit)										44,238	42,403	36,409
Net income (loss)		$ 13,625	$ 26,232	$ 12,512	$ 22,267	$ 14,355	$ 20,030	$ 12,022	$ 24,235	74,636	70,642	59,468
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues										835,417	830,245	789,518
Depreciation and amortization										77,036	65,978	64,237
Total interest charges and financing costs										26,494	23,448	22,966
Income tax expense (benefit)										40,654	39,621	33,691
Net income (loss)										69,398	59,060	51,334
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										120,645	174,514	134,834
Depreciation and amortization										14,034	13,501	12,485
Total interest charges and financing costs										2,637	2,358	2,749
Income tax expense (benefit)										2,501	5,993	4,623
Net income (loss)										4,862	8,714	6,501
All Other
Segment Reporting Information [Line Items]
Operating revenues										1,396	1,085	1,003
Depreciation and amortization										175	175	175
Total interest charges and financing costs										90	107	101
Income tax expense (benefit)										1,083	(3,211)	(1,905)
Net income (loss)										376	2,868	1,633
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[1]									956,541	1,000,462	923,038
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[1]									834,998	829,748	789,168
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	[1]									120,147	169,629	132,867
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	[1]									1,396	1,085	1,003
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues										(917)	(5,382)	(2,317)
Depreciation and amortization										0	0	0
Total interest charges and financing costs										0	0	0
Income tax expense (benefit)										0	0	0
Net income (loss)										0	0	0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues										419	497	350
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										498	4,885	1,967
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues										$ 0	$ 0	$ 0

[1] Operating revenues include $163 million, $145 million and $137 million of intercompany revenue for the years ended Dec. 31, 2015, 2014 and 2013 respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Deferred Purchased Power Costs		$ 5,200
Transmission costs deferred as regulatory liability		11,000
Operating revenues
Electric	$ 163,255	145,102	$ 136,917
Related Party Transaction, Utilities Operating Expense, Purchased Power net of deferred costs		430,666
Operating expenses
Purchased power	419,028	425,471	416,173
Transmission expense	54,070	43,876	42,460
Natural gas purchased for resale	45	90	97
Other operating expenses - paid to Xcel Energy Services Inc.	93,890	84,224	61,531
Interest expense	2	30	$ 22
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	71	31
Accounts payable	24,538	26,524
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	18,268	17,333
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	71	22
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	71	31
Accounts payable	0	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	$ 6,199	$ 9,169

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Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 229,607	$ 236,161	$ 216,813	$ 273,960	$ 256,160	$ 231,046	$ 228,114	$ 285,142	$ 956,541	$ 1,000,462	$ 923,038
Operating income	27,809	47,532	25,069	39,549	27,787	37,540	23,730	42,571	139,959	131,628	117,181
Net income	$ 13,625	$ 26,232	$ 12,512	$ 22,267	$ 14,355	$ 20,030	$ 12,022	$ 24,235	$ 74,636	$ 70,642	$ 59,468

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Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 5,821	$ 4,911	$ 4,333
Charged to costs and expenses		3,947	4,431	3,988
Charged to other accounts	[1]	1,161	1,269	1,199
Deductions from reserves	[2]	5,801	4,790	4,609
Balance at Dec. 31		$ 5,128	$ 5,821	$ 4,911

[1] Recovery of amounts previously written off.

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