10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

or

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

Commission file number 001-03140

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Wisconsin	39-0508315
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1414 West Hamilton Avenue, Eau Claire, Wisconsin 54701

(Address of principal executive offices)

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

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

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

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

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

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

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

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

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

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

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

As of Feb. 23, 2015, 933,000 shares of common stock, par value $100 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2014 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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

TABLE OF CONTENTS

Index

PART I
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	7
Fuel Sources	7
Renewable Energy Sources	8
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	24
Item 3 — Legal Proceedings	25
Item 4 — Mine Safety Disclosures	25
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6 — Selected Financial Data	25
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	28
Item 8 — Financial Statements and Supplementary Data	29
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
Item 9A — Controls and Procedures	72
Item 9B — Other Information	72
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	72
Item 11 — Executive Compensation	72
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
Item 13 — Certain Relationships and Related Transactions, and Director Independence	72
Item 14 — Principal Accountant Fees and Services	72
PART IV
Item 15 — Exhibits, Financial Statement Schedules	72
SIGNATURES	75

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
WDNR	Wisconsin Department of Natural Resources
Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
FCA	Fuel clause adjustment
PGA	Purchased gas adjustment
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
C&I	Commercial and Industrial
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CO2	Carbon dioxide
CPCN	Certificate of public convenience and necessity
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles

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GHG	Greenhouse gas
LNG	Liquefied natural gas
MACT	Maximum Achievable Control Technology
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
MVP	Multi-Value Project
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NOL	Net operating loss
NOx	Nitrogen oxide
NSPS	New source performance standard
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
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
ROFR	Right of first refusal
RPS	Renewable portfolio standards
RSG	Revenue sufficiency guarantee
RTO	Regional Transmission Organization
ROFR	Right of first refusal
SO2	Sulfur dioxide
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 255,000 customers and natural gas utility service to approximately 111,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2014.  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; providing options and solutions to customers; 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 2015, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2012	2013	2014	2015 Forecast
NSP System	9,475	9,524	8,848	9,301

The peak demand for the NSP System typically occurs in the summer. The 2014 uninterrupted system peak demand for the NSP System occurred on July 21, 2014. The 2014 system peak demand was lower due to cooler summer weather. The 2015 forecast assumes normal peak day weather.

Energy Sources and Related Transmission Initiatives

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

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

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

NSP System Resource Plans — In January 2015, NSP-Minnesota filed its 2016-2030 Resource Plan with the MPUC, proposing to achieve a 40 percent reduction in carbon emissions by 2030 from 2005 levels through the significant addition of renewables, continued commitment to specific CIP annual achievements, and the continued operation of its existing cost-effective thermal generation.  The plan positions NSP-Minnesota to be responsive to future environmental requirements and market trends, builds on the significant investments already made in the NSP System, and acknowledges the divergence in state energy policies within the NSP System. Key points of the resource plan include:

• Adding 600 MW of wind by 2020 and 1,200 MW by 2027, bringing total wind power on the NSP System to over 3,600 MW;

• Adding 187 MW of large-scale solar energy by 2016 and an additional 1,700 MW of large-scale solar and 500 MW of customer-driven small-scale solar; bringing total solar power on the NSP System to approximately 2,400 MW;

• Operating the Monticello and PI nuclear plants through their current licenses; and

• Continuing to run Sherco Units 1 and 2 with gradually decreasing reliance through 2030.

In February 2015, the MPUC approved the Competitive Acquisition Plan (CAP), in which NSP-Minnesota is required to add capacity to its system to meet a resource need as follows:

• Enter into an agreement for 100 MW of distributed solar with Geronimo Energy LLC;

• Enter into an agreement with Calpine Corporation for a 345 MW expansion at its Mankato Energy Center; and

• Construct a 215 MW Black Dog Unit 6 combustion turbine.

NSP-Minnesota also proposed use of a collaborative stakeholder process to guide its five-year action plan, and to facilitate the necessary update of its resource analysis to incorporate the CAP outcomes and significantly higher than expected response to its Community Solar Gardens program.

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CapX2020 CPCN — The PSCW issued a CPCN for the Wisconsin portion of the Hampton, Minn. to La Crosse, Wis. project in May 2012. The Wisconsin route is approximately 50 miles of new transmission line with an estimated cost of $211 million. The line is expected to go into service in the fall of 2015.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line— In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, known as the Badger Coulee line, would run between 154 and 187 miles based on the permitted route, which includes AFUDC, of between $540 and $580 million. NSP-Wisconsin’s half of the project is shared with two partners, Dairyland Power Cooperative and WPPI Energy. NSP-Wisconsin’s portion of the investment is estimated to be between $190 and $207 million. In 2011, MISO determined the line to be a MVP project, and as such, eligible for cost sharing under MISO’s MVP tariff. The PSCW held hearings on the application in January 2015, and a decision is expected by April 2015. If approved, NSP-Wisconsin and ATC anticipate beginning construction on the line in late 2016, with completion by late 2018.

Fuel Supply and Costs

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

	Coal (a)				Nuclear				Natural Gas				Weighted Average Owned Fuel Cost
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent
2014	$	2.23	52	%	$	0.89	42	%	$	6.27	6	%	$	1.94
2013	2.20		49		0.95		40		5.08		11		2.03
2012	2.13		47		0.90		42		4.21		11		1.88

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

The higher cost of natural gas was primarily due to higher market prices from increased demand because of cold weather in early 2014.

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

Fuel Sources

Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2014 and 2013 were approximately 27 and 34 days usage, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana. During 2014 and 2013, coal requirements for the NSP System’s major coal-fired generating plants were approximately 9.3 million tons and 7.3 million tons, respectively. Coal requirements for 2014 were higher as Sherco Unit 3 was placed back in service. The estimated coal requirements for 2015 are approximately 8.7 million tons, which reflects the retirement of Black Dog Units 3 and 4.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 88 percent of their estimated coal requirements in 2015, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the first year, 67 percent of requirements in year two, and 33 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 2015 and 2016. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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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 72 percent of the requirements for 2019 through 2027.

• Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 62 percent of the requirements for 2022 through 2027.

• Current enrichment service contracts cover 100 percent of the requirements through 2021 and approximately 68 percent of the requirements for 2025 through 2027.

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 spot market price volatility will remain due to index-based pricing structures contained in certain supply contracts.

Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies, 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, 2014 and 2013, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $349 million and $389 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2015 to 2028.

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

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2014, 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 24.2 percent and 22.9 percent of the NSP System’s total owned and purchased energy for 2014 and 2013, respectively.

• Wind energy comprised 13.7 percent and 12.6 percent of the total owned and purchased energy on the NSP System for 2014 and 2013, respectively.

• Hydroelectric energy comprised 7.8 percent and 7.4 percent of the total owned and purchased energy on the NSP System for 2014 and 2013, respectively.

• Biomass and solar power comprised approximately 2.7 percent and 3.0 percent of the total owned and purchased energy on the NSP System for 2014 and 2013, 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 2014, the number of customers utilizing Windsource increased to approximately 43,000 from 37,000 in 2013. Windsource MWh sales increased from approximately 181,000 MWh in 2013 to 186,000 MWh 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 915 PV systems with approximately 11.1 MW of aggregate capacity and over 679 PV systems with approximately 7.3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2014 and 2013, respectively.

8

Wind—The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota. Currently, the NSP System has more than 100 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 two wind farms which have the capacity to generate 302 MWs. Collectively, the NSP System had approximately 1,860 MWs of wind energy on its system at the end of 2014 and 2013. In October 2013, the MPUC approved four new projects, which are anticipated to provide up to 750 MW of capacity, including two projects totaling 350 MW that will be owned by NSP-Minnesota. One additional 20 MW project was approved in 2014. All five projects are targeted to be operational in late 2015. With the new projects, the NSP System is anticipated to have approximately 2,630 MWs of wind power. 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 $41 for 2014 and 2013. 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 2014 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2014, with certain projects qualifying into future years.

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 268 MW of capacity. For 2014, PPAs provided approximately 38 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

Summary of Recent Federal Regulatory Developments

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

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In October 2014, the FERC upheld the determination of the long-term growth rate to be used in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000)— In 2011, the FERC issued a final ruling, Order 1000, adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. Order 1000 requires:

• The development of tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region;

• The coordination between regions for the development of interregional plans for transmission planning and cost allocation;

• Each public utility transmission provider to amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; and

• The removal of ROFR provisions from FERC-jurisdictional wholesale transmission contracts and tariffs that presently grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area.

MISO has submitted multiple compliance filings with the FERC to implement the Order 1000 requirements. Some of the new compliance provisions that were filed have already been approved but others remain under review by the FERC.

In August 2014, the D.C. Circuit denied all appeals and upheld Order 1000 in its entirety and indicated that challenges to the removal of federal ROFR provisions from individual contracts or tariffs could be considered in individual compliance filings. The FERC’s decisions to remove federal ROFR provisions in certain MISO agreements were appealed to federal courts of appeal in 2014, and those appeals are pending. The removal of a federal ROFR would eliminate rights that NSP-Wisconsin currently has under the MISO tariffs to build certain transmission projects within its footprint.

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Order 1000 could create opportunities for third parties to build and own certain regional transmission projects that had previously been reserved for the MISO transmission owners, potentially reducing NSP-Wisconsin’s financial return on new investments in electric transmission facilities. The ultimate impact of Order 1000 on future NSP-Wisconsin transmission investment is not known at this time.

NERC Critical Infrastructure Protection Requirements — The FERC has approved version 5 of NERC’s critical infrastructure protection standards. Requirements must be applied 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 evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

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 will become enforceable in October 2015 with staggered milestone deliverable dates through 2016.  NSP-Wisconsin is currently in the process of developing and performing the initial risk assessment in accordance with the requirements of the standard, which will provide a basis to estimate the cost of protections necessary to meet 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 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 over SPP transmission facilities between the traditional MISO region in the Midwest and the Entergy system. Several cases have been filed with the FERC by MISO and SPP. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to January 2014, and set the issues for settlement judge and hearing procedures. If SPP is successful in charging MISO for use of the SPP system, the NSP System would experience higher costs from MISO, which could be material, but SPS would collect revenues from SPP. The outcome of the JOA disputes, and the potential impact on NSP-Wisconsin, are uncertain at this time.

Xcel Energy Services Inc. and NSP-Wisconsin vs. American Transmission Company, LLC (ATC) (La Crosse, Wis. to Madison, Wis. Transmission Line) —In February 2012, Xcel Energy Services Inc. and NSP-Wisconsin filed a complaint with the FERC concerning ownership of the proposed La Crosse, Wis. to Madison, Wis. 345 KV transmission line. In July 2012, the FERC ruled favorably on Xcel Energy Services Inc.’s and NSP-Wisconsin’s complaint, ruling that the responsibilities to construct the La Crosse, Wis. to Madison, Wis. transmission line, also known as the Badger Coulee line, belong equally to NSP-Wisconsin and ATC. In August 2012, ATC requested rehearing and requested that the FERC grant a stay of the ruling. ATC and NSP-Wisconsin jointly filed a CPCN application with the PSCW for the project in October 2013. In May 2014, the FERC issued an order denying the ATC request for rehearing and motion for stay. The 60 day period for ATC to appeal the FERC order lapsed, making the FERC ruling final.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2014			2013			2012
Electric sales (Millions of KWh)
Residential	1,984			1,990			1,921
Large commercial and industrial	1,823			1,698			1,739
Small commercial and industrial	2,902			2,837			2,763
Public authorities and other	42			36			35
Total retail	6,751			6,561			6,458
Sales for resale	—			1			412
Total energy sold	6,751			6,562			6,870
Number of customers at end of period
Residential	214,350			213,665			211,727
Large commercial and industrial	114			107			108
Small commercial and industrial	38,939			38,549			38,359
Public authorities and other	1,144			1,149			1,153
Total retail	254,547			253,470			251,347
Wholesale	—			—			9
Total customers	254,547			253,470			251,356
Electric revenues (Thousands of Dollars)
Residential	$	254,277		$	247,081		$	223,191
Large commercial and industrial	136,435			125,151			120,694
Small commercial and industrial	282,016			267,796			247,003
Public authorities and other	6,636			6,184			5,762
Total retail	679,364			646,212			596,650
Wholesale	1,341			2,524			31,583
Interchange revenues from NSP-Minnesota	145,102			136,917			125,344
Other electric revenues	3,941			3,515			3,988
Total electric revenues	$	829,748		$	789,168		$	757,565
KWh sales per retail customer	26,522			25,885			25,694
Revenue per retail customer	$	2,669		$	2,549		$	2,374
Residential revenue per KWh		12.82	¢		12.42	¢		11.62	¢
Large commercial and industrial revenue per KWh	7.48			7.37			6.94
Small commercial and industrial revenue per KWh	9.72			9.44			8.94
Total retail revenue per KWh	10.06			9.85			9.24
Wholesale revenue per KWh (a)	n/a			n/a			7.67

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

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Energy Source Statistics

	Year Ended Dec. 31
	2014			2013			2012
NSP System	Millions ofKWh	Percent of Generation		Millions ofKWh	Percent of Generation		Millions ofKWh	Percent of Generation
Coal	18,079	39	%	15,844	36	%	16,023	35	%
Nuclear	13,434	29		12,161	28		13,231	29
Natural Gas	3,402	7		5,550	13		6,200	13
Wind (a)	6,243	14		5,481	13		5,443	12
Hydroelectric	3,560	8		3,223	7		3,193	7
Other (b)	1,417	3		1,323	3		1,617	4
Total	46,135	100	%	43,582	100	%	45,707	100	%
Owned generation	33,641	73	%	29,249	67	%	31,365	69	%
Purchased generation	12,494	27		14,333	33		14,342	31
Total	46,135	100	%	43,582	100	%	45,707	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 seven, eight, and six net million KWh for 2014, 2013, and 2012, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of NSP‑Wisconsin are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2014, average annual sales to the typical NSP‑Wisconsin residential customer declined 15 percent, while sales to the typical small C&I customer increased 10 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 purchased gas adjustment cost-recovery mechanism for Wisconsin operations to recover the actual cost of natural gas and transportation and storage services.  The PSCW has the authority to disallow certain costs if it finds NSP-Wisconsin was not prudent in its procurement activities.

NSP-Wisconsin’s natural gas rate schedules for Michigan customers include a natural gas cost-recovery factor, which is based on 12-month projections.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 163,520 MMBtu, which occurred on Jan. 6, 2014, and 155,087 MMBtu, which occurred on Jan. 21, 2013.

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 131,857 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 13 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2014-2015 supply plan was approved by the PSCW in October 2014.

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:

2014	$	6.52
2013	4.51
2012	4.36

The higher cost of natural gas was primarily due to higher market prices from increased demand because of cold weather in early 2014.

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 2015 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, 2014, NSP-Wisconsin was committed to approximately $71 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 8 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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

Natural Gas Operating Statistics

	Year Ended Dec. 31
	2014		2013		2012
Natural gas deliveries (Thousands of MMBtu)
Residential	8,098		7,505		5,737
Commercial and industrial	10,626		10,131		8,197
Total retail	18,724		17,636		13,934
Transportation and other	4,729		4,344		4,177
Total deliveries	23,453		21,980		18,111
Number of customers at end of period
Residential	98,325		96,974		95,715
Commercial and industrial	12,773		12,646		12,506
Total retail	111,098		109,620		108,221
Transportation and other	23		23		22
Total customers	111,121		109,643		108,243
Natural gas revenues (Thousands of Dollars)
Residential	$	82,851	$	67,745	$	51,302
Commercial and industrial	82,181		63,896		47,771
Total retail	165,032		131,641		99,073
Transportation and other	4,597		1,226		4,027
Total natural gas revenues	$	169,629	$	132,867	$	103,100
MMBtu sales per retail customer	168.54		160.88		128.76
Revenue per retail customer	$	1,485	$	1,201	$	915
Residential revenue per MMBtu	10.23		9.03		8.94
Commercial and industrial revenue per MMBtu	7.73		6.31		5.83
Transportation and other revenue per MMBtu	0.97		0.28		0.96

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 on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

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The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, NSP-Wisconsin 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 future environmental regulations under consideration 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, 2014, NSP-Wisconsin had 567 full-time employees and three part-time employees, of which 402 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 of Directors is to identify, manage and mitigate material risk. Our Board employs an effective process for doing so, combining management and Board risk oversight. The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees regarding risk management. As provided below, management and each committee has responsibility for overseeing aspects of risk management and mitigation of the risk.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability, broadly considering our business, the utility industry, the domestic and global economy and the environment. 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 of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board in presentations and communications over the course of the year.

The Board has assigned several important aspects of its governance and oversight to four standing committees to ensure issues and risks are well understood and effectively managed. While the Board as a whole reviews management’s key risk assessment and analyzes areas of potential future risk to Xcel Energy, the committees provide focused oversight of specific risks assigned to them. This provides robust and comprehensive risk management that is critical to successful execution of corporate strategy.

Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards.  Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2014, 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 seeking to protect the environment may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂, CO₂ and other GHGs, particulates and cooling water intake systems.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk. Physical risks from climate change include changes in weather conditions, changes in precipitation and extreme weather events.

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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 affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand 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 could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as a tax on GHGs, 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 in our utility operations.  We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.

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

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

We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity. However, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC’s rules permit us to deal in utility operations-related swaps with utility special entities and not be required to register as a swap dealer provided that our aggregate gross notional amount of swap dealing activity (including utility operations-related swaps) does not exceed the general de minimis threshold and provided that we have not exceeded the special entity de minimis threshold (excluding utility operations-related swaps) of $25 million for the preceding 12 months. Our current level of financial swap activity with special entities is significantly below this special entity de minimis threshold; therefore, we will not be classified as a swap dealer in our special entity activity. Swap transactions with non-special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act. We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

We may at times have direct credit exposure as part of our local gas distribution company supply activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties.  We may also have some indirect credit exposure due to participation in organized markets, such as 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 substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans with modifications to these funding requirements that allowed additional flexibility in the timing of contributions.  Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company 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 to the consolidated financial statements, 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 authorized or anticipated costs.  Any such disruption, if significant, would cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.  The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation 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 of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

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

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

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

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

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

Our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed generation, customer behavioral response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. NSP-Wisconsin’s aging infrastructure may pose a risk to system reliability and expose us to premature financial obligations. NSP-Wisconsin is engaged in significant and ongoing infrastructure investment programs.

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

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

Our natural gas transmission and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  We maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results of operations. For our natural gas transmission or distribution lines located near populated areas the level of potential damages resulting from these risks is greater.

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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 intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. 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, 2014, Xcel Energy Inc. and its utility subsidiaries had approximately $11.5 billion of long-term debt and $1.3 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, 2014, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $13.9 million and $0.2 million of exposure. Xcel Energy also had additional guarantees of $31.4 million at Dec. 31, 2014 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 2014, 2013 and 2012 we paid $43.8 million, $31.0 million and $57.3 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of certain amounts if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level. See Item 5 for further discussion on dividend limitations.

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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.

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. 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 under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and has proposed regulations to reduce GHG emissions from existing power plants that are expected to become final in 2015, with state plans to achieve the EPA’s goals due by 2017. Such regulations could impose substantial costs on our system. The EPA has also proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built which may be adopted in 2015. If adopted, these regulations could significantly increase the cost of building new generating plants.

The United States continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change (UNFCCC). In 2014, the United States and China jointly announced GHG emissions goals. Further, the 20^th Conference of the Parties (COP) to the UNFCCC concluded with the objective of developing an agreement among countries on emission reductions at the 2015 COP. This could result in additional GHG regulation or reduction goals 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.

There are many uncertainties regarding when and in what form climate change legislation or regulations will be imposed. The impact of legislation and regulations will depend on a number of factors, including what GHG emission reduction goals are set, what flexibility is allowed to meet the goals, how and whether early action to reduce GHG emissions is credited, whether GHG sources in other sectors of the economy are regulated, the degree to which GHG offsets are recognized as compliance options, how any emission allowances would be allocated to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. In addition, international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements 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 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.  In addition, NERC electric reliability standards are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations.  If a serious reliability incident did occur, it could have a material effect on our operations or financial results. 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 both positively and negatively. 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 are 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 that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business.  We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, including NSP-Minnesota’s nuclear power plants under the NRC’s design basis threat requirements.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance may decrease.  In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

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

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

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

We operate in 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.

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

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

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

Item 1B — Unresolved Staff Comments

None.

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 2014 Net Dependable Capability (MW)
Steam:
Bay Front-Ashland, Wis., 3 Units	Coal/Wood/Natural Gas	1948-1956	56
French Island-La Crosse, Wis., 2 Units	Wood/Refuse-derived fuel	1940-1948	16	(a)
Combustion Turbine:
Flambeau Station-Park Falls, Wis., 1 Unit	Natural Gas	1969	12
French Island-La Crosse, Wis., 2 Units	Natural Gas	1974	122
Wheaton-Eau Claire, Wis., 6 Units	Natural Gas	1973	290
Hydro:
Various locations, 63 Units	Hydro	Various	135
		Total	631

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

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2014:

Conductor Miles
345 KV	1,152
161 KV	1,575
115 KV	1,746
Less than 115 KV	32,408

NSP-Wisconsin had 201 electric utility transmission and distribution substations at Dec. 31, 2014.

Natural gas utility mains at Dec. 31, 2014:

Miles
Distribution	2,316

Item 3 — Legal Proceedings

NSP-Wisconsin is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.  Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.  In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Additional Information

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

Item 4 — Mine Safety Disclosures

None.

PART II

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

NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. NSP-Wisconsin has dividend restrictions imposed by FERC rules and state regulatory commissions:

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

• The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission. NSP-Wisconsin cannot pay annual dividends during 2014 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 52.8 percent at Dec. 31, 2014 and $8.3 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 2014 and 2013 were as follows:

(Thousands of Dollars)	2014		2013
First quarter	$	8,057	$	7,519
Second quarter	16,243		7,757
Third quarter	11,486		8,037
Fourth quarter	14,957		8,032

Item 6 — Selected Financial Data

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

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

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

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Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Wisconsin and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slowdown 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; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Wisconsin’s Form 10-K and Exhibit 99.01 hereto.

Results of Operations

NSP-Wisconsin’s net income was $70.6 million for 2014 compared with $59.5 million for 2013.  An electric rate increase led to higher electric margin, while weather-normalized sales growth positively impacted both electric and natural gas margins. These increases were partially offset by additional O&M expenses.

Electric Revenues and Margin

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

(Millions of Dollars)	2014			2013
Electric revenues	$	830		$	789
Electric fuel and purchased power	(445		)	(434		)
Electric margin	$	385		$	355

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

Electric Revenues

(Millions of Dollars)	2014 vs. 2013
Retail rate increase (Wisconsin)	$	23
Interchange agreement billings with NSP-Minnesota	9
Retail sales growth, excluding weather impact	7
Fuel and purchased power cost recovery	2
Estimated impact of weather	(3		)
Other, net	3
Total increase in electric revenues	$	41

Electric Margin

(Millions of Dollars)	2014 vs. 2013
Retail rate increase (Wisconsin)	$	23
Fuel recovery	11
Retail sales growth, excluding weather impact	7
Interchange agreement billings with NSP-Minnesota	(9		)
Estimated impact of weather	(3		)
Other, net	1
Total increase in electric margin	$	30

Natural Gas Revenues and Margin

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

(Millions of Dollars)	2014			2013
Natural gas revenues	$	170		$	133
Cost of natural gas sold and transported	(114		)	(82		)
Natural gas margin	$	56		$	51

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)	2014 vs. 2013
Purchased natural gas adjustment clause recovery	$	34
Estimated impact of weather	1
Retail sales growth, excluding weather impact	1
Other, net	1
Total increase in natural gas revenues	$	37

Natural Gas Margin

(Millions of Dollars)	2014 vs. 2013
Estimated impact of weather	$	1
Retail sales growth, excluding weather impact	1
Other, net	3
Total increase in natural gas margin	$	5

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Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased$15.7 million, or 8.9 percent, for 2014 compared with 2013.  The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2014 vs. 2013
Interchange agreement billings with NSP-Minnesota	$	12
Transmission expense	1
Electric and natural gas distribution expenses	1
Plant generation costs	1
Other, net	1
Total increase in O&M expenses	$	16

Depreciation and Amortization — Depreciation and amortization increased$2.8 million, or 3.6 percent, for 2014 compared with 2013. The increase is primarily attributable to a change in amortization as a result of regulatory outcomes.

AFUDC, Equity and Debt— AFUDC increased$4.2 million for 2014 compared with 2013. The increase is primarily due to the expansion of transmission facilities.

Income Taxes — Income tax expense increased$6.0 million for 2014 compared with 2013.  The increase in income tax expense was primarily due to higher pretax earnings in 2014. This was partially offset by increased permanent plant-related adjustments in 2014. The ETR was 37.5 percent for 2014, compared with 38.0 percent for 2013.

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.

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At Dec. 31, 2014 and 2013, a 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact annual pretax interest expense by approximately $0.8 million and $0.7 million, respectively.  See Note 9 to the consolidated financial statements for a discussion of NSP-Wisconsin’s interest rate derivatives.

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

At Dec. 31, 2014, a 10 percent increase or decrease in commodity prices would have an immaterial impact on credit exposure. At Dec. 31, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $0.6 million, while a decrease in prices of 10 percent would have an immaterial impact on credit exposure.

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, 2014. 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, 2014, 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. 23, 2015	Feb. 23, 2015

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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, 2014 and 2013, 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, 2014.  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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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 23, 2015

31

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2014			2013			2012
Operating revenues
Electric	$	829,748		$	789,168		$	757,565
Natural gas	169,629			132,867			103,100
Other	1,085			1,003			1,177
Total operating revenues	1,000,462			923,038			861,842
Operating expenses
Electric fuel and purchased power, non-affiliates	19,595			18,129			19,440
Purchased power, affiliates	425,471			416,173			405,016
Cost of natural gas sold and transported	114,250			81,572			61,370
Operating and maintenance expenses	191,213			175,522			167,503
Conservation program expenses	11,537			12,333			14,442
Depreciation and amortization	79,654			76,897			69,234
Taxes (other than income taxes)	27,114			25,231			24,971
Total operating expenses	868,834			805,857			761,976
Operating income	131,628			117,181			99,866
Other income, net	270			253			476
Allowance for funds used during construction — equity	7,060			4,259			2,104
Interest charges and financing costs
Interest charges — includes other financing costs of $1,570, $1,538, and $1,574, respectively	29,273			27,797			24,799
Allowance for funds used during construction — debt	(3,360		)	(1,981		)	(1,862		)
Total interest charges and financing costs	25,913			25,816			22,937
Income before income taxes	113,045			95,877			79,509
Income taxes	42,403			36,409			29,558
Net income	$	70,642		$	59,468		$	49,951

See Notes to Consolidated Financial Statements

32

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2014		2013		2012
Net income	$	70,642	$	59,468	$	49,951
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $51, $51 and $51, respectively.	76		76		77
Other comprehensive income	76		76		77
Comprehensive income	$	70,718	$	59,544	$	50,028

See Notes to Consolidated Financial Statements

33

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2014			2013			2012
Operating activities
Net income	$	70,642		$	59,468		$	49,951
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	80,875			78,048			70,372
Deferred income taxes	45,396			25,789			27,107
Amortization of investment tax credits	(527		)	(664		)	(626		)
Allowance for equity funds used during construction	(7,060		)	(4,259		)	(2,104		)
Provision for bad debts	4,431			3,988			3,329
Net derivative losses (gains)	10			(279		)	127
Changes in operating assets and liabilities:
Accounts receivable	(5,558		)	(12,702		)	(15,953		)
Accrued unbilled revenues	(1,933		)	(2,496		)	(470		)
Inventories	(3,210		)	(1,879		)	6,018
Other current assets	(3,501		)	(3,749		)	(3,172		)
Accounts payable	2,936			(1,811		)	5,828
Net regulatory assets and liabilities	(34,697		)	(2,062		)	3,623
Other current liabilities	(911		)	7,589			3,681
Pension and other employee benefit obligations	(6,134		)	(8,759		)	(10,857		)
Change in other noncurrent assets	(113		)	232			14
Change in other noncurrent liabilities	2,534			1,119			(595		)
Net cash provided by operating activities	143,180			137,573			136,273
Investing activities
Utility capital/construction expenditures	(288,209		)	(201,278		)	(152,759		)
Allowance for equity funds used during construction	7,060			4,259			2,104
Other, net	(166		)	(421		)	916
Net cash used in investing activities	(281,315		)	(197,440		)	(149,739		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	10,000			29,000			(27,000		)
Proceeds from notes payable to affiliates	30			—			50
Repayments of notes payable to affiliates	—			(80		)	—
Proceeds from issuance of long-term debt	98,534			—			97,916
Repayments of long-term debt	(107		)	(160		)	(97		)
Capital contributions from parent	73,432			58,977			2,796
Dividends paid to parent	(43,818		)	(30,980		)	(57,311		)
Net cash provided by financing activities	138,071			56,757			16,354
Net change in cash and cash equivalents	(64		)	(3,110		)	2,888
Cash and cash equivalents at beginning of period	1,349			4,459			1,571
Cash and cash equivalents at end of period	$	1,285		$	1,349		$	4,459
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(24,442	)	$	(24,376	)	$	(21,035	)
Cash received (paid) for income taxes, net	3,474			(9,842		)	(5,841		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	35,267		$	27,222		$	10,618

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
	2014			2013
Assets
Current assets
Cash and cash equivalents	$	1,285		$	1,349
Accounts receivable, net	60,396			59,269
Accrued unbilled revenues	53,567			51,634
Inventories	24,685			21,475
Regulatory assets	20,036			14,866
Prepaid taxes	28,628			27,518
Deferred income taxes	8,201			14,953
Prepayments and other	6,918			5,056
Total current assets	203,716			196,120
Property, plant and equipment, net	1,674,281			1,442,779
Other assets
Regulatory assets	280,693			233,193
Other investments	3,818			3,650
Other	4,612			3,651
Total other assets	289,123			240,494
Total assets	$	2,167,120		$	1,879,393
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,235		$	107
Short-term debt	78,000			68,000
Notes payable to affiliates	500			470
Accounts payable	61,530			52,086
Accounts payable to affiliates	26,524			24,986
Dividends payable to parent	14,957			8,032
Regulatory liabilities	16,940			9,717
Environmental liabilities	29,116			28,785
Other	19,923			22,521
Total current liabilities	248,725			214,704
Deferred credits and other liabilities
Deferred income taxes	348,180			305,139
Deferred investment tax credits	9,089			9,698
Regulatory liabilities	132,674			126,424
Environmental liabilities	78,620			79,703
Customer advances	17,623			16,008
Pension and employee benefit obligations	51,313			45,708
Other	16,151			9,237
Total deferred credits and other liabilities	653,650			591,917
Commitments and contingencies
Capitalization
Long-term debt	567,056			468,490
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2014 and 2013, respectively	93,300			93,300
Additional paid in capital	322,276			248,844
Retained earnings	282,398			262,499
Accumulated other comprehensive loss	(285		)	(361		)
Total common stockholder’s equity	697,689			604,282
Total liabilities and equity	$	2,167,120		$	1,879,393

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, 2011	933,000	$	93,300	$	187,071	$	241,296		$	(514	)	$	521,153
Net income						49,951						49,951
Other comprehensive income									77			77
Common dividends declared to parent						(56,871		)				(56,871		)
Contribution of capital by parent				2,796								2,796
Balance at Dec. 31, 2012	933,000	$	93,300	$	189,867	$	234,376		$	(437	)	$	517,106
Net income						59,468						59,468
Other comprehensive income									76			76
Common dividends declared to parent						(31,345		)				(31,345		)
Contribution of capital by parent				58,977								58,977
Balance at Dec. 31, 2013	933,000	$	93,300	$	248,844	$	262,499		$	(361	)	$	604,282
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

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
	2014			2013
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
June 15, 2024, 3.3%	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%	523			558
Other	1,687			1,760
Unamortized discount	(2,519		)	(2,321		)
Total	568,291			468,597
Less current maturities	1,235			107
Total long-term debt	$	567,056		$	468,490
Common Stockholder’s Equity
Common stock  — 1,000,000 shares authorized of $100 par value;
933,000 shares outstanding at Dec. 31, 2014 and 2013, respectively	$	93,300		$	93,300
Additional paid in capital	322,276			248,844
Retained earnings	282,398			262,499
Accumulated other comprehensive loss	(285		)	(361		)
Total common stockholder’s equity	$	697,689		$	604,282

^(a)  Resource recovery financing

See Notes to Consolidated Financial Statements

37

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 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, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

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

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

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

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

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NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased electric energy and fuel for electric generation. 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.

NSP-Wisconsin is required to contribute 1.2 percent of its annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates on the customer utility bills. There is no financial incentive given back 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 3.3, 3.5 and 3.5 percent for the years ended Dec. 31, 2014, 2013 and 2012, 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.

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. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

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

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

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

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments— NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense.  NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

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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.

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Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates 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, 2014 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. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. NSP-Wisconsin is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Accounts receivable, net (a)
Accounts receivable	66,217		64,180
Less allowance for bad debts	(5,821	)	(4,911	)
	60,396		59,269

^(a)  Accounts receivable, net includes an immaterial amount and $1,595 due from affiliates for 2014 and 2013, respectively.

(Thousands of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	6,494	$	6,437
Fuel	6,654		5,915
Natural gas	11,537		9,123
	$	24,685	$	21,475

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(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	2,061,669		$	1,913,354
Natural gas plant	255,465			236,047
Common and other property	125,938			112,886
CWIP	231,413			127,954
Total property, plant and equipment	2,674,485			2,390,241
Less accumulated depreciation	(1,000,204		)	(947,462		)
	$	1,674,281		$	1,442,779

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, 2014
Borrowing limit	$	150
Amount outstanding at period end	78
Average amount outstanding	34
Maximum amount outstanding	80
Weighted average interest rate, computed on a daily basis	0.37		%
Weighted average interest rate at period end	0.55

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	150		$	150		$	150
Amount outstanding at period end	78			68			39
Average amount outstanding	46			20			61
Maximum amount outstanding	101			71			116
Weighted average interest rate, computed on a daily basis	0.27		%	0.31		%	0.39		%
Weighted average interest rate at period end	0.55			0.27			0.40

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, 2014 and 2013, 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.

Amended Credit Agreement —In October 2014, NSP-Wisconsin entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for NSP-Wisconsin remained at $150 million.

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

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

• The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. NSP-Wisconsin was in compliance as its debt-to-total capitalization ratio was 48 percent and 47 percent at Dec. 31, 2014 and 2013, 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.

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

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

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

At Dec. 31, 2014, NSP-Wisconsin had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn(b)		Available
$	150.0	$	78.0	$	72.0

^(a)  These credit facilities have been amended to extend the maturity to 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, 2014 and 2013.

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, 2014			Dec. 31, 2013
Notes payable to affiliates	$	0.5		$	0.5
Weighted average interest rate	0.51		%	0.24		%

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 June 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 $4.3 million and $3.5 million, net of amortization, at Dec. 31, 2014 and 2013, respectively.  NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

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

The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of approximately $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 52.8 percent at Dec. 31, 2014 and $8.3 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, 2014:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		CWIP		Ownership %
Electric Transmission:
CapX2020 Transmission	$	26,434	$	8,082	$	103,940	80.7	%
La Crosse, Wis. to Madison, Wis.	—		—		9,814		50.0
Total NSP-Wisconsin	$	26,434	$	8,082	$	113,754

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

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. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. 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, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. At Dec. 31, 2014, the IRS has begun the Appeals process; however, the outcome and timing of a resolution is uncertain.

State Audits— NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2014, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. In the first quarter of 2014, the state of Wisconsin commenced an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of Dec. 31, 2014, there were no state income tax audits in progress.

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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, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	2.9		1.4
Total unrecognized tax benefit	$	3.0	$	1.5

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

(Millions of Dollars)	2014			2013			2012
Balance at Jan. 1	$	1.5		$	1.3		$	1.5
Additions based on tax positions related to the current year	1.9			0.7			0.5
Reductions based on tax positions related to the current year	(0.2		)	—			(0.2		)
Additions for tax positions of prior years	0.1			0.5			0.3
Reductions for tax positions of prior years	(0.2		)	—			(0.8		)
Settlements with taxing authorities	(0.1		)	(1.0		)	—
Balance at Dec. 31	$	3.0		$	1.5		$	1.3

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, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(0.9	)	$	(0.4	)

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 process progresses and state audits resume. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2014, 2013 and 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2014, 2013 or 2012.

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)	2014	2013
Federal NOL carryforward	48.5	46.8
Federal tax credit carryforwards	4.5	4.4
State NOL carryforward	3.4	6.3

The federal carryforward periods expire between 2021 and 2034.  The state carryforward periods expire between 2022 and 2031.

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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:

	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.9		5.0		3.4
Tax credits recognized	(0.7	)	(0.9	)	(0.9	)
Regulatory differences — utility plant items	(1.6	)	(0.9	)	(0.3	)
Change in unrecognized tax benefits	—		—		0.1
Other, net	(0.1	)	(0.2	)	(0.1	)
Effective income tax rate	37.5	%	38.0	%	37.2	%

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

(Thousands of Dollars)	2014			2013			2012
Current federal tax expense (benefit)	$	(3,932	)	$	5,902		$	930
Current state tax expense	453			4,628			2,216
Current change in unrecognized tax expense (benefit)	1,013			754			(69		)
Deferred federal tax expense	38,321			23,794			25,089
Deferred state tax expense	8,042			2,720			1,890
Deferred change in unrecognized tax (benefit) expense	(967		)	(725		)	128
Deferred investment tax credits	(527		)	(664		)	(626		)
Total income tax expense	$	42,403		$	36,409		$	29,558

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

(Thousands of Dollars)	2014			2013			2012
Deferred tax expense excluding items below	$	49,793		$	27,516		$	27,995
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(4,346		)	(1,676		)	(837		)
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	45,396		$	25,789		$	27,107

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

(Thousands of Dollars)	2014		2013
Deferred tax liabilities:
Difference between book and tax bases of property	$	319,265	$	287,121
Regulatory assets	72,670		57,296
Employee benefits	18,691		16,953
Other	14,453		10,193
Total deferred tax liabilities	$	425,079	$	371,563
Deferred tax assets:
Environmental remediation	43,207		43,501
NOL carryforward	18,283		17,384
Regulatory liabilities	10,460		6,205
Deferred investment tax credits	5,628		5,976
Tax credit carryforward	4,515		4,440
Other	3,007		3,871
Total deferred tax assets	$	85,100	$	81,377
Net deferred tax liability	$	339,979	$	290,186

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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, 2014, NSP-Wisconsin had 402 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016.

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

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

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

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

Specific valuation methods include the following:

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

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

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

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

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

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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, 2014 and 2013 were $46.5 million and $36.5 million, respectively, of which $0.8 million and $0.6 million, respectively, was attributable to NSP-Wisconsin. In 2014 and 2013, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4.7 million and $6.6 million, respectively, of which amounts attributable to NSP-Wisconsin were immaterial. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. 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 2014 and 2013 were below the assumed level of 7.25 percent in both years;

• Investment returns in 2012 were above the assumed level of 7.50 percent; and

• In 2015, NSP-Wisconsin’s expected investment-return assumption is 7.25 percent.

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

The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year:

	2014		2013
Domestic and international equity securities	39	%	31	%
Long-duration fixed income and interest rate swap securities	23		29
Short-to-intermediate term fixed income securities	14		16
Alternative investments	22		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.

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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, 2014 and 2013:

	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

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

The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfer 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.

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

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)	2014			2013
Accumulated Benefit Obligation at Dec. 31	$	153,590		$	153,894
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	163,930		$	179,995
Service cost	4,527			5,682
Interest cost	7,257			6,924
Plan amendments	—			(1,109		)
Actuarial loss (gain)	9,126			(11,097		)
Benefit payments	(19,171		)	(16,465		)
Obligation at Dec. 31	$	165,669		$	163,930

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	136,935		$	136,546
Actual return on plan assets	6,916			5,525
Employer contributions	8,033			11,329
Benefit payments	(19,171		)	(16,465		)
Fair value of plan assets at Dec. 31	$	132,713		$	136,935

(Thousands of Dollars)	2014			2013
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(32,956	)	$	(26,995	)

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

(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	90,007	$	84,773
Prior service cost	667		778
Total	$	90,674	$	85,551

(Thousands of Dollars)	2014		2013
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	$	6,728	$	7,631
Noncurrent regulatory assets	83,946		77,920
Total	$	90,674	$	85,551

Measurement date Dec. 31, 2014 Dec. 31, 2013

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	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.11	%	4.75	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2014		RP 2000

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.

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 2012 through 2015 to meet minimum funding requirements.

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

• $90.0 million in January 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;

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

• $198.1 million in 2012, of which $12.5 million was attributable to NSP-Wisconsin.

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

Plan Amendments — In 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)	2014			2013			2012
Service cost	$	4,527		$	5,682		$	4,568
Interest cost	7,257			6,924			7,765
Expected return on plan assets	(9,642		)	(9,995		)	(10,489		)
Amortization of prior service cost	111			417			1,771
Amortization of net loss	6,617			7,924			6,004
Net periodic pension cost	$	8,870		$	10,952		$	9,619

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.75	%	4.00	%	5.00	%
Expected average long-term increase in compensation level	3.75		3.75		4.00
Expected average long-term rate of return on assets	7.25		7.25		7.50

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In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to NSP-Wisconsin were $1.7 million, $2.2 million and $1.8 million in 2014, 2013 and 2012, 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 7.25 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including NSP-Wisconsin, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes NSP-Wisconsin, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for NSP-Wisconsin was approximately $1.4 million in 2014, $1.3 million in 2013 and $1.2 million in 2012.

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Wisconsin, has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. The former NSP, which includes NSP-Wisconsin, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

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

Regulatory agencies for nearly all retail 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:

	2014		2013
Domestic and international equity securities	25	%	41	%
Short-to-intermediate fixed income securities	57		40
Alternative investments	13		13
Cash	5		6
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, 2014 and 2013:

	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

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

For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:

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

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

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

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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)	2014			2013
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	17,153		$	19,432
Service cost	35			25
Interest cost	791			760
Medicare subsidy reimbursements	2			31
Plan participants’ contributions	284			621
Actuarial gain	(38		)	(1,724		)
Benefit payments	(1,459		)	(1,992		)
Obligation at Dec. 31	$	16,768		$	17,153

(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	746		$	647
Actual return on plan assets	(15		)	(13		)
Plan participants’ contributions	284			621
Employer contributions	956			1,483
Benefit payments	(1,459		)	(1,992		)
Fair value of plan assets at Dec. 31	$	512		$	746

(Thousands of Dollars)	2014			2013
Funded Status of Plans at Dec. 31:
Funded status	$	(16,256	)	$	(16,407	)
Current liabilities	(1,022		)	(718		)
Noncurrent liabilities	(15,234		)	(15,689		)
Net postretirement amounts recognized on consolidated balance sheets	$	(16,256	)	$	(16,407	)

(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	10,461		$	11,098
Prior service credit	(2,836		)	(3,187		)
Total	$	7,625		$	7,911

(Thousands of Dollars)	2014		2013
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	$	95	$	570
Noncurrent regulatory assets	7,530		7,341
Total	$	7,625	$	7,911

Measurement date Dec. 31, 2014 Dec. 31, 2013

	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.08	%	4.82	%
Mortality table	RP 2014		RP 2000
Health care costs trend rate — initial	6.50	%	7.00	%

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Effective Jan. 1, 2015, the initial medical trend rate was decreased from 7.0 percent to 6.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is four 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	$	1,722	$	(1,450	)
Service and interest components	98		(80		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes NSP-Wisconsin, contributed $17.1 million, $17.6 million and $47.1 million during 2014, 2013 and 2012, respectively, of which $1.0 million, $1.5 million and $1.9 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $12.8 million during 2015, of which $1.5 million is attributable to NSP-Wisconsin.

Plan Amendments — In 2014 and 2013, 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)	2014			2013			2012
Service cost	$	35		$	25		$	20
Interest cost	791			760			1,075
Expected return on plan assets	(52		)	(42		)	(50		)
Amortization of transition obligation	—			1			171
Amortization of prior service credit	(351		)	(351		)	(14		)
Amortization of net loss	666			963			486
Net periodic postretirement benefit cost	$	1,089		$	1,356		$	1,688

	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.82	%	4.10	%	5.00	%
Expected average long-term rate of return on assets	7.08		7.11		6.75

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
2015	$	12,517	$	1,547	$	13	$	1,534
2016	13,288		1,473		11		1,462
2017	13,164		1,397		9		1,388
2018	12,564		1,352		8		1,344
2019	13,289		1,311		7		1,304
2020-2024	65,118		5,816		30		5,786

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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, 2014, 2013 and 2012. 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)	2014		2013		2012
Multiemployer plan contributions:
Pension	$	156	$	130	$	163
Total	$	156	$	130	$	163

8. Other Income, Net

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

(Thousands of Dollars)	2014			2013			2012
Interest income	$	368		$	538		$	736
Other nonoperating income	321			152			129
Insurance policy expense	(409		)	(427		)	(389		)
Other nonoperating expense	(10		)	(10		)	—
Other income, net	$	270		$	253		$	476

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.

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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, 2014, 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)	2014	2013
MMBtu of natural gas	18	987

^(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)	2014			2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(361	)	$	(437	)	$	(514	)
After-tax net realized losses on derivative transactions reclassified into earnings	76			76			77
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(285	)	$	(361	)	$	(437	)

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, 2014, 2013 and 2012.

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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. During the years ended Dec. 31, 2013 and 2012, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million and $0.4 million, respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

During the year ended Dec. 31, 2014, immaterial natural gas commodity derivatives settlement gains were recognized and losses totaling $0.7 million and $2.9 million were recognized for each of the years ended Dec. 31, 2013 and 2012, 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, 2014, 2013 and 2012. 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, 2014
	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	$	—	$	52	$	—	$	52	$	—	$	52

	Dec. 31, 2013
	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	$	—	$	580	$	—	$	580	$	—	$	580

^(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, 2014 and 2013.  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 $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.

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

Fair Value of Long-Term Debt

As of Dec. 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2014				2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	568,291	$	670,665	$	468,597	$	518,269

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, 2014 and 2013, 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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10. Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

Wisconsin 2015 Electric Rate Case—In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request was for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes were requested to the capital structure or the 10.2 percent ROE authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers.

In December 2014, the PSCW issued its order approving an overall increase in NSP-Wisconsin’s electric rates of approximately $14.2 million, or 2.2 percent, reflecting the updated November forecast for fuel and purchased power costs. The PSCW order was consistent with the agreement reached by the parties, as described above. The new rates were effective Jan. 1, 2015.

Pending Regulatory Proceedings - Michigan Public Service Commission (MPSC)

Michigan 2015 Electric Rate Case — In October 2014, NSP-Wisconsin filed a request with the MPSC to increase rates for electric service by $900,000, or 6.1 percent. The filing was based on a 2015 forecast test year, a 10.3 percent ROE, an equity ratio of 52.59 percent and a forecasted average rate base of approximately $35.2 million. The primary drivers of the requested increase are continuing investment in transmission and distribution infrastructure. The filing also included a request for a $289,000, or 1.9 percent, step increase in 2016, to reflect the expiration in 2016 of certain credits that were used to offset the 2015 rate request. In addition to the MPSC staff, intervenors in the case include the Michigan Attorney General and the Association of Businesses Advocating Tariff Equity, a voluntary association of large industrial businesses. Hearings are scheduled for April 2015. The parties have agreed to meet in February 2015 to discuss potential settlement of the case.

Pending Regulatory Proceedings — FERC

MISO ROE Complaint/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for RTO membership and being an independent transmission company), effective Nov. 12, 2013.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections.

In October 2014, the FERC upheld the determination of the long-term growth rate to be used together with a short term growth rate in its new ROE methodology. The FERC separately set the ROE complaint against the MISO transmission owners for settlement judge and hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. The settlement judge procedures were unsuccessful. FERC action is pending. In January 2015, the ROE complaint was set for full hearing procedures, with an ALJ initial decision to be issued by November 2015 and a FERC order issued no earlier than 2016.

In November 2014, the MISO transmission owners filed a request for FERC approval of a 50 basis point RTO membership ROE adder, with collection deferred until resolution of the ROE complaint. In January 2015, the FERC approved the ROE adder, 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. In 2015, several intervenors sought rehearing of the commission order.

In February 2015, a separate group of customers filed an additional complaint proposing to reduce the MISO region ROE to 8.67 percent, prior to any 50 basis point RTO adder, with a refund effective date of Feb. 12, 2015.  Answers to the complaint are to be filed by March 2015.

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NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of Dec. 31, 2014. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $5 million and $7 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 2015 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, 2014 are as follows:

(Millions of dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2015	$	6.6	$	12.4	$	13.2
2016	0.8		0.3		13.1
2017	0.9		0.2		10.4
2018	0.8		—		4.7
2019	0.8		—		3.1
Thereafter	3.3		—		13.5
Total (a)	$	13.2	$	12.9	$	58.0

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

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

Leases— NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business. These leases, primarily for office space, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $1.3 million, $1.4 million and $1.1 million for 2014, 2013 and 2012, respectively.

Future commitments under operating leases are:

(Millions of Dollars)
2015	$	0.9
2016	0.9
2017	1.0
2018	1.0
2019	1.0
Thereafter	7.9
Total	$	12.7

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.

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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, 2014		Dec. 31, 2013
Current assets	$	246	$	223
Property, plant and equipment, net	2,278		2,427
Other noncurrent assets	122		112
Total assets	$	2,646	$	2,762
Current liabilities	$	1,349	$	233
Mortgages and other long-term debt payable	486		1,687
Other noncurrent liabilities	48		42
Total liabilities	$	1,883	$	1,962

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

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $13.6 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $127.3 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $19.0 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.

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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 $17.9 million for business interruption insurance and $43.6 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	$	0.2	2018	(a)

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

Environmental Contingencies

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

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

MGP Sites

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

The EPA issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.

In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.

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In October 2012, a settlement among the EPA, the WDNR, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. Demolition activities occurred at the Ashland site in 2013. The final design for the soil, including excavation and treatment, as well as containment wall remedies was submitted to the EPA in April 2014 and work commenced in May 2014. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and those activities are expected to commence in 2015. Based on these updated designs, the cost estimate for the cleanup of the Phase I Project Area is approximately $54 million, of which approximately $28 million has already been spent. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA. In September 2014, the EPA granted an extension of time to perform the pilot in the summer of 2015.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter is scheduled for April-May of 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing. A settlement in principle has been reached with two PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”), the EPA and NSP-Wisconsin resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. Under the agreement, the Railroad PRPs have agreed to contribute $10.5 million to the costs of the cleanup at the Ashland site. The agreement is currently subject to a 30-day public comment period and must be entered by the U.S. District Court for the Western District of Wisconsin before it will become final. It is anticipated that the agreement will be entered in the first quarter of 2015. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers.

At Dec. 31, 2014 and 2013, NSP-Wisconsin had recorded a liability of $107.6 million and $104.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $28.9 million and $25.2 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, external MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process. Any payments received from insurance carriers or PRPs are recorded as a reduction of the regulatory asset. Once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four- to six-year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

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In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize these estimated costs over a ten-year period; and (3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area. The PSCW determined the timing of the cleanup of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the cleanup in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility.

Other MGP Sites— NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited. NSP-Wisconsin has identified two sites where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the remediation at these sites will continue through at least 2015. NSP-Wisconsin had accrued $0.2 million and $3.9 million for both of these sites at Dec. 31, 2014 and 2013, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. NSP-Wisconsin anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste

Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Wisconsin has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017, but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.

Federal CWA Section 316(b)— 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 estimates the likely cost for complying with impingement requirements is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the second quarter of 2015.

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Coal Ash Regulation— NSP-Wisconsin’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2010, the EPA published a proposed rule on the regulation of coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. The EPA issued a pre-publication version of the final rule in December 2014, which once promulgated will impose new rules to regulate coal ash as a nonhazardous solid waste. NSP-Wisconsin has ceased coal combustion at Bay Front Unit 5 and will not have any units subject to coal ash regulation. Due to the Interchange Agreement, NSP-Wisconsin may incur costs related to this rule but does not expect these to have a material impact on the results of operations, financial position or cash flows.

Air

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments were due to the EPA on Dec. 1, 2014 and a final rule is anticipated in mid-summer 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Wisconsin operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG NSPS Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. A final rule is anticipated in mid-summer 2015. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule is anticipated in mid-summer 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at NSP-Wisconsin’s power plants.

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.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering CSAPR’s predecessor rule pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the CAA and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in February 2015. While the litigation continues, the EPA will begin to administer the CSAPR in 2015.

NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO₂ due to cessation of coal combustion at Bay Front Unit 5. NSP-Wisconsin anticipates compliance with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows.

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Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. NSP-Wisconsin will not have any units subject to EGU MATS because it has ceased coal combustion in Bay Front Unit 5. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. It is not yet known what impact the Supreme Court’s decision may have on the MATS standard or its implementation schedule.

Industrial Boiler (IB) MACT Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The controls to meet the requirements were substantially complete as of Dec. 31, 2014, with final work targeted to be finished in May 2015. The final capital cost is estimated to be approximately $21 million.

Revisions to the National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where NSP-Wisconsin operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In December 2014, the EPA issued its final designations, which did not include areas in any states in which NSP-Wisconsin operates.

Revisions to the NAAQS for Ozone— In December 2014, the EPA proposed to revise the NAAQS for ozone by lowering the eight-hour standard from 0.075 parts per million (ppm) to a level within the range of 0.065-0.070 ppm. The EPA is also taking comment on a level for the standard as low as 0.060 ppm. Current monitored air quality concentrations in areas of Wisconsin where NSP-Wisconsin operates are below the range of the proposed standard. The EPA is expected to adopt a new ozone standard in a final rule to be issued in October 2015. Depending on the level of the standard, impacted states would study the sources of the nonattainment and make emission reduction plans to attain the standards. These plans would be due to the EPA in 2020 or 2021. Such plans could include installation of further NOx controls on power plants. It is not possible to evaluate the impact of this proposal until the final standard is adopted, the designation of nonattainment areas is made in late 2017 based on air quality data years 2014-2016, and any required state plans are developed.

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 the electric production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. 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. The origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities.

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, treated poles, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

In December 2014, the EPA issued a pre-publication version of a final rule imposing requirements for activities involving coal ash waste. The ruling, once effective, will not result in the creation of a new legal obligation or impact NSP-Wisconsin’s estimated cash flows for the closure of coal ash landfills and impoundments.

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A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2014 and 2013 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow Revisions		Ending Balance Dec. 31, 2014 (a)
Electric plant
Steam production asbestos	$	2,005	$	—	$	44	$	—	$	2,049
Steam and other 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 (b)	$	2,853	$	515	$	76	$	5,646	$	9,090

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

^(a)  There were no ARO liabilities settled during the years ended Dec. 31, 2014 or 2013.

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

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, 2014 and 2013 were $123 million and $116 million, respectively.

Legal Contingencies

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

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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, 2014 and 2013 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Environmental remediation costs	1, 11	Various	$	4,376	$	147,793	$	4,376	$	117,684
Pension and retiree medical obligations (a)	7	Various	6,837		91,601		8,202		85,220
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		16,711		—		12,679
Losses on reacquired debt	4	Term of related debt	801		4,936		801		5,737
State commission adjustments	1	Plant lives	488		11,650		410		9,355
Conservation programs	1	Less than one year	—		—		404		—
Deferred income tax adjustment	1, 6	Typically plant lives	—		1,514		—		1,763
Recoverable purchased natural gas and electric energy costs		Less than one year	6,946		—		673		—
Monticello EPU		Pending rate cases	—		5,237		—		—
Other		Various	588		1,251		—		755
Total regulatory assets			$	20,036	$	280,693	$	14,866	$	233,193

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

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2014 and 2013 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	123,105	$	—	$	116,293
DOE settlement	11	Less than one year	4,931		—		6,814		—
Investment tax credit deferrals	1, 6	Various	—		9,397		—		9,976
Conservation programs	1	Less than one year	1,010		—		1,187		—
Deferred electric production and natural gas costs	1	Less than one year	—		—		1,542		—
Excess depreciation reserve		Various	10,999		—		—		—
Other		Various	—		172		174		155
Total regulatory liabilities			$	16,940	$	132,674	$	9,717	$	126,424

At Dec. 31, 2014 and 2013, approximately $12.1 million and $0.1 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.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2014			Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(361	)	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	76			76
Net current period OCI	76			76
Accumulated other comprehensive loss at Dec. 31	$	(285	)	$	(361	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2014				Year Ended Dec. 31, 2013
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
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 (benefit)	33,691		4,623		(1,905		)	—			36,409
Net Income	51,334		6,501		1,633			—			59,468

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	757,565	$	103,100	$	1,177	$	—		$	861,842
Intersegment revenues	355		727		—		(1,082		)	—
Total revenues	$	757,920	$	103,827	$	1,177	$	(1,082	)	$	861,842
Depreciation and amortization	$	59,768	$	9,251	$	215	$	—		$	69,234
Interest charges and financing costs	20,303		2,554		80		—			22,937
Income tax expense	27,164		2,113		281		—			29,558
Net Income	45,377		3,094		1,480		—			49,951

^(a)  Operating revenuesinclude $145 million, $137 million and $125 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012 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)	2014		2013		2012
Operating revenues:
Electric	$	145,102	$	136,917	$	125,344
Operating expenses:
Purchased power (a)	430,666		416,173		405,016
Transmission expense	43,876		42,460		44,942
Natural gas purchased for resale	90		97		116
Other operating expenses — paid to Xcel Energy Services Inc.	84,224		61,531		54,137
Interest expense	30		22		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:

	2014				2013
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	17,333	$	—	$	18,584
PSCo	—		22		—		8
SPS	31		—		26		—
Other subsidiaries of Xcel Energy Inc.	—		9,169		1,569		6,394
	$	31	$	26,524	$	1,595	$	24,986

16. Summarized Quarterly Financial Data (Unaudited)

	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

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

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, 2014, 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, 2014 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Wisconsin conducted testing and monitoring of its internal control over financial reporting.  Based on the control evaluation, testing and remediation performed, NSP-Wisconsin did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

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

Item 9B — Other Information

None.

PART III

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

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

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

Item 13 — Certain Relationships and Related Transactions, and Director Independence

Item 14 — Principal Accountant Fees and Services

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2014 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2014
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Consolidated Balance Sheets — As of Dec. 31, 2014 and 2013.
	Consolidated Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Consolidated Statements of Capitalization — As of Dec. 31, 2014 and 2013.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2014, 2013 and 2012.

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)).
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).

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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-Q 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-Q 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).
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)).
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, 2014 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) the Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, and (ix) Schedule II.

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SCHEDULE II

NSP-WISCONSIN AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2014, 2013 AND 2012

(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:
2014	$	4,911	$	4,431	$	1,269	$	4,790	$	5,821
2013	4,333		3,988		1,199		4,609		4,911
2012	4,766		3,329		1,310		5,072		4,333

^(a)  Recovery of amounts previously written off.

^(b)  Principally bad debts written off.

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SIGNATURES

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

	NORTHERN STATES POWER COMPANY (A WISCONSIN CORPORATION)
Feb. 23, 2015	/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.

75

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
	2014		2013		2012		2011		2010
Earnings, as defined:
Pretax income	$	113,045	$	95,877	$	79,509	$	84,620	$	68,861
Add: Fixed charges	29,686		28,325		25,215		24,628		24,897
Total earnings, as defined	$	142,731	$	124,202	$	104,724	$	109,248	$	93,758
Fixed charges, as defined:
Interest charges	$	29,273	$	27,797	$	24,799	$	24,168	$	24,517
Interest component of leases	413		528		416		460		380
Total fixed charges, as defined	$	29,686	$	28,325	$	25,215	$	24,628	$	24,897
Ratio of earnings to fixed charges	4.8		4.4		4.2		4.4		3.8

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-192835 on Form S-3 of our report dated February 23, 2015, 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, 2014.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 23, 2015

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. 23, 2015

/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. 23, 2015

/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, 2014, 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. 23, 2015

/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 for the year ended Dec. 31, 2014, or in other publicly disseminated written documents.

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

1

XML

Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014 and 2013 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2014			Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(361	)	$	(437	)
Losses reclassified from net accumulated other comprehensive loss	76			76
Net current period OCI	76			76
Accumulated other comprehensive loss at Dec. 31	$	(285	)	$	(361	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2014				Year Ended Dec. 31, 2013
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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Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2014 Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (in hundredths)	71.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	402

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Amount outstanding at period end	78,000	$ 68,000
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

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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
Cash Flow Hedges [Member] | Interest Rate [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net		(100,000)	(100,000)
Designated as Hedging Instrument [Member] | Cash Flow Hedges [Member] | Interest Rate [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(100,000)
Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	100,000	(100,000)	(400,000)
Derivative Instruments Gain Loss Reclassified To Regulatory Assets And Liabilities Net		$ (700,000)	$ (2,900,000)

XML

Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2014
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

XML

Commitments and Contingencies, Guarantees (Details) (Payment or Performance Guarantee, Customer Loans for Farm Rewiring Program, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Payment or Performance Guarantee | Customer Loans for Farm Rewiring Program
Guarantee [Abstract]
Assets held as collateral	$ 0
Guarantees issued and outstanding	1.0	[1]
Current exposure under guarantees	$ 0.2	[1]
Guarantee Expiration Date (year)	2018	[1]

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

XML

Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 2,674,485	$ 2,390,241
Less accumulated depreciation	(1,000,204)	(947,462)
Property, plant and equipment, net	1,674,281	1,442,779
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,061,669	1,913,354
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	255,465	236,047
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	125,938	112,886
CWIP
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 231,413	$ 127,954

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.1	$	0.1
Unrecognized tax benefit — Temporary tax positions	2.9		1.4
Total unrecognized tax benefit	$	3.0	$	1.5

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

(Millions of Dollars)	2014			2013			2012
Balance at Jan. 1	$	1.5		$	1.3		$	1.5
Additions based on tax positions related to the current year	1.9			0.7			0.5
Reductions based on tax positions related to the current year	(0.2		)	—			(0.2		)
Additions for tax positions of prior years	0.1			0.5			0.3
Reductions for tax positions of prior years	(0.2		)	—			(0.8		)
Settlements with taxing authorities	(0.1		)	(1.0		)	—
Balance at Dec. 31	$	3.0		$	1.5		$	1.3

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, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(0.9	)	$	(0.4	)

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)	2014	2013
Federal NOL carryforward	48.5	46.8
Federal tax credit carryforwards	4.5	4.4
State NOL carryforward	3.4	6.3

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:

	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.9		5.0		3.4
Tax credits recognized	(0.7	)	(0.9	)	(0.9	)
Regulatory differences — utility plant items	(1.6	)	(0.9	)	(0.3	)
Change in unrecognized tax benefits	—		—		0.1
Other, net	(0.1	)	(0.2	)	(0.1	)
Effective income tax rate	37.5	%	38.0	%	37.2	%

Schedule of Components of Income Tax Expense (Benefit)

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

(Thousands of Dollars)	2014			2013			2012
Current federal tax expense (benefit)	$	(3,932	)	$	5,902		$	930
Current state tax expense	453			4,628			2,216
Current change in unrecognized tax expense (benefit)	1,013			754			(69		)
Deferred federal tax expense	38,321			23,794			25,089
Deferred state tax expense	8,042			2,720			1,890
Deferred change in unrecognized tax (benefit) expense	(967		)	(725		)	128
Deferred investment tax credits	(527		)	(664		)	(626		)
Total income tax expense	$	42,403		$	36,409		$	29,558

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

(Thousands of Dollars)	2014			2013			2012
Deferred tax expense excluding items below	$	49,793		$	27,516		$	27,995
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(4,346		)	(1,676		)	(837		)
Tax expense allocated to other comprehensive income	(51		)	(51		)	(51		)
Deferred tax expense	$	45,396		$	25,789		$	27,107

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)	2014		2013
Deferred tax liabilities:
Difference between book and tax bases of property	$	319,265	$	287,121
Regulatory assets	72,670		57,296
Employee benefits	18,691		16,953
Other	14,453		10,193
Total deferred tax liabilities	$	425,079	$	371,563
Deferred tax assets:
Environmental remediation	43,207		43,501
NOL carryforward	18,283		17,384
Regulatory liabilities	10,460		6,205
Deferred investment tax credits	5,628		5,976
Tax credit carryforward	4,515		4,440
Other	3,007		3,871
Total deferred tax assets	$	85,100	$	81,377
Net deferred tax liability	$	339,979	$	290,186

XML

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 Parties Site	Dec. 31, 2013
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites, current	$ 29,116,000	$ 28,785,000
Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Number of properties included in superfund site which NSP-Wisconsin does not own	2
Liability for estimated cost of remediating sites	107,600,000	104,600,000
Number of PRPs that have reached a settlement in principle	2
Contributions to site cleanup by PRPs	10,500,000
Number of days the agreement is subject to public comment	30 days
Liability for estimated cost of remediating sites, current	28,900,000	25,200,000
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years)	4 years
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years)	6 years
Ashland MGP Site - Phase I Project Area
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites	54,000,000
Estimated amount spent on Phase I Project Area cleanup	28,000,000
Approved amortization period for recovery of remediation costs in natural gas rates (in years)	10 years
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths)	3.00%
Approved increase (decrease) in amortization expense granted by a regulatory body	1,100,000
Ashland MGP Site - Sediments
Manufactured Gas Plant (MGP) Site [Abstract]
Estimated cost of remediating site, low end of range	63,000,000
Estimated cost of remediating site, high end of range	77,000,000
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)	50.00%
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)	30.00%
Other MGP Sites
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for estimated cost of remediating sites	$ 200,000	$ 3,900,000
Number of identified MGP sites under current investigation and/or remediation	2

XML

Rate Matters (Details) (USD $)	1 Months Ended						12 Months Ended	1 Months Ended
	May 31, 2014	Dec. 31, 2014	Oct. 31, 2014	Nov. 30, 2013	Nov. 30, 2014	Jun. 30, 2014	Dec. 31, 2014	Feb. 28, 2015
PSCW Proceeding - Wisconsin Electric Rate Case 2015 [Member] | Public Service Commission of Wisconsin (PSCW)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 20,600,000
Public Utilities, Requested Rate Increase (Decrease), Percentage	3.20%
NSP-Wisconsin [Member] | PSCW Proceeding - Wisconsin Electric Rate Case 2015 [Member] | Public Service Commission of Wisconsin (PSCW)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		14,200,000
Public Utilities, Approved Rate Increase (Decrease), Percentage		2.20%
NSP-Wisconsin [Member] | MPSC Proceeding - Electric Rate Case 2015, Electric Rates 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			289,000
Public Utilities, Requested Rate Increase (Decrease), Percentage			1.90%
NSP-Wisconsin [Member] | MPSC Proceeding - Electric Rate Case 2015, Electric Rates 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			900,000
Public Utilities, Requested Rate Increase (Decrease), Percentage			6.10%
Public Utilities, Requested Return on Equity, Percentage			10.30%
Public Utilities, Requested Equity Capital Structure, Percentage			52.59%
Public Utilities, Requested Rate Base, Amount			35,200,000
NSP-Wisconsin [Member] | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, maximum equity capital structure percentage allowed per the complaint				50.00%
NSP-Wisconsin [Member] | 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
Minimum | NSP-Wisconsin [Member] | 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				9.15%
Public Utilities, reduction of transmission revenue, net of expense due to the new ROE methodology							5,000,000
Maximum | NSP-Wisconsin [Member] | 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, reduction of transmission revenue, net of expense due to the new ROE methodology							$ 7,000,000
Subsequent Event | FERC Proceeding, MISO ROE Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties								50
Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties								8.67%

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Summarized Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 256,160	$ 231,046	$ 228,114	$ 285,142	$ 240,388	$ 231,060	$ 210,175	$ 241,415	$ 1,000,462	$ 923,038	$ 861,842
Operating income	27,787	37,540	23,730	42,571	16,545	40,769	22,466	37,401	131,628	117,181	99,866
Net income	$ 14,355	$ 20,030	$ 12,022	$ 24,235	$ 7,225	$ 22,013	$ 10,544	$ 19,685	$ 70,642	$ 59,468	$ 49,951

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) (Pension Plans, USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 132,713	$ 136,935	$ 136,546
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12,334	8,865
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	110,791	118,269
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	9,588	9,801	14,894	15,807
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,910	4,332
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,910	4,332
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	28	937
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	28	937
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	16,084	6,711
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	16,084	6,711
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	13,231	24,955
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	13,231	24,955
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	162	307
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	162	307
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	749	1,578
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	475	684
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	475	684
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	3,781
Common stock
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,424	4,533
Common stock | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,424	4,533
Common stock | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Common stock | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,078	7,502
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,078	7,502	8,545	8,440
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	81,806	84,364
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	81,806	84,364
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	2,510	2,299
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	2,510	2,299	3,472	2,008
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	(995)	311
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	(995)	311
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

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Commitments and Contingencies, Variable Interest Entities (Details) (Low-Income Housing Limited Partnerships [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Low-Income Housing Limited Partnerships [Member]
Amounts Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 246	$ 223
Property, plant and equipment, net	2,278	2,427
Other noncurrent assets	122	112
Total assets	2,646	2,762
Current liabilities	1,349	233
Mortgages and other long-term debt payable	486	1,687
Other noncurrent liabilities	48	42
Total liabilities	$ 1,883	$ 1,962

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Segments and Related Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Intercompany revenue									$ 145,102		$ 136,917		$ 125,344
Operating revenues	256,160	231,046	228,114	285,142	240,388	231,060	210,175	241,415	1,000,462		923,038		861,842
Depreciation and amortization									79,654		76,897		69,234
Total interest charges and financing costs									25,913		25,816		22,937
Income tax expense (benefit)									42,403		36,409		29,558
Net income (loss)	14,355	20,030	12,022	24,235	7,225	22,013	10,544	19,685	70,642		59,468		49,951
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									830,245		789,518		757,920
Depreciation and amortization									65,978		64,237		59,768
Total interest charges and financing costs									23,448		22,966		20,303
Income tax expense (benefit)									39,621		33,691		27,164
Net income (loss)									59,060		51,334		45,377
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									174,514		134,834		103,827
Depreciation and amortization									13,501		12,485		9,251
Total interest charges and financing costs									2,358		2,749		2,554
Income tax expense (benefit)									5,993		4,623		2,113
Net income (loss)									8,714		6,501		3,094
All Other
Segment Reporting Information [Line Items]
Operating revenues									1,085		1,003		1,177
Depreciation and amortization									175		175		215
Total interest charges and financing costs									107		101		80
Income tax expense (benefit)									(3,211)		(1,905)		281
Net income (loss)									2,868		1,633		1,480
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues									1,000,462	[1]	923,038	[1]	861,842	[1]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									829,748	[1]	789,168	[1]	757,565	[1]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									169,629	[1]	132,867	[1]	103,100	[1]
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues									1,085	[1]	1,003	[1]	1,177	[1]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues									(5,382)		(2,317)		(1,082)
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									497		350		355
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									4,885		1,967		727
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues									$ 0		$ 0		$ 0

[1] Operating revenues include $145 million, $137 million and $125 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012 respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Commitments and Contingencies, Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 2,853	[1],[2]	$ 3,036
Liabilities recognized	515		0
Liabilities settled	0		0
Accretion	76		84
Cash Flow Revisions	5,646		(267)
Ending balance	9,090	[1],[2]	2,853	[1],[2]
Electric Plant Steam Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	2,005	[1]	1,962
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	44		43
Cash Flow Revisions	0		0
Ending balance	2,049	[1]	2,005	[1]
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	361	[1]	125
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	13		12
Cash Flow Revisions	0		224
Ending balance	374	[1]	361	[1]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	36	[1]	13
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	1		1
Cash Flow Revisions	0		22
Ending balance	37	[1]	36	[1]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	289	[1]	826
Liabilities recognized	113		0
Liabilities settled	0		0
Accretion	10		20
Cash Flow Revisions	0		(557)
Ending balance	412	[1]	289	[1]
Natural Gas Plant Gas Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	75	[1]	75
Liabilities recognized	402		0
Liabilities settled	0		0
Accretion	5		5
Cash Flow Revisions	5,645		(5)
Ending balance	6,127	[1]	75	[1]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	87	[1]	35
Liabilities recognized	0		0
Liabilities settled	0		0
Accretion	3		3
Cash Flow Revisions	1		49
Ending balance	$ 91	[1]	$ 87	[1]

[1] There were no ARO liabilities settled during the years ended Dec. 31, 2014 or 2013.

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

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Schedule II, Valuation and Qualifying Accounts (Details) (Allowance for Bad Debts, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Bad Debts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1	$ 4,911		$ 4,333		$ 4,766
Charged to costs and expenses	4,431		3,988		3,329
Charged to other accounts	1,269	[1]	1,199	[1]	1,310	[1]
Deductions from reserves	4,790	[2]	4,609	[2]	5,072	[2]
Balance at Dec. 31	$ 5,821		$ 4,911		$ 4,333

[1] Recovery of amounts previously written off.

[2] Principally bad debts written off.

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Commitments and Contingencies, Joint Operating System (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 Counterparty
Joint Operating System [Abstract]
Number of companies covered by FERC approved Interchange Agreement	2
NSP-Minnesota | Nuclear Insurance
Joint Operating System [Abstract]
Maximum possible loss contingency	13,600,000,000
Nuclear insurance coverage secured for the Company's public liability exposure	375,000,000
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,200,000,000
Maximum assessments per reactor per accident	127,300,000
Number of owned and licensed reactors	3
Maximum funding requirement per reactor for any one year	19,000,000
Term for maximum installment payment assessment per reactor (in years)	1 year
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,300,000,000
Number of nuclear plant sites operated by NSP-Minnesota	2
Maximum assessments for business interruption insurance each calendar year	17,900,000
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	43,600,000

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Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Prepayments and other	$ 6,918		$ 5,056
Other current liabilities	19,923		22,521
Fair Value Measured on a Recurring Basis | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	52	[1]	580	[2]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	52		580
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Fair Value Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Prepayments and other	6,900
Other current liabilities			5,100
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	52		580
Fair Value Measured on a Recurring Basis | Netting [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 0	[3]	$ 0	[3]

[1] Included in other current assets balance of $6.9 million at Dec. 31, 2014 in the consolidated balance sheets.

[2] Included in other current assets balance of $5.1 million at Dec. 31, 2013 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, 2014 and 2013. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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Segments and Related Information

12 Months Ended

Dec. 31, 2014

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
2012
Operating revenues (a)	$	757,565	$	103,100	$	1,177	$	—		$	861,842
Intersegment revenues	355		727		—		(1,082		)	—
Total revenues	$	757,920	$	103,827	$	1,177	$	(1,082	)	$	861,842
Depreciation and amortization	$	59,768	$	9,251	$	215	$	—		$	69,234
Interest charges and financing costs	20,303		2,554		80		—			22,937
Income tax expense	27,164		2,113		281		—			29,558
Net Income	45,377		3,094		1,480		—			49,951

^(a)  Operating revenuesinclude $145 million, $137 million and $125 million of intercompany revenue for the years ended Dec. 31, 2014, 2013 and 2012 respectively. See Note 15 for further discussion of related party transactions by operating segment.

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Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangements and Other Short-Term Borrowings (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 470
Notes Payable, Other Payables
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Weighted average interest rate at period end (percentage)	0.51%	0.24%

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	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

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

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Commitments and Contingencies, Leases (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leases [Abstract]
Total expenses under operating lease obligations	$ 1.3	$ 1.4	$ 1.1
Other [Member]
Operating Leases, Future Minimum Payments Due [Abstract]
2015	0.9
2016	0.9
2017	1.0
2018	1.0
2019	1.0
Thereafter	7.9
Total	$ 12.7

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014 are as follows:

(Millions of dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2015	$	6.6	$	12.4	$	13.2
2016	0.8		0.3		13.1
2017	0.9		0.2		10.4
2018	0.8		—		4.7
2019	0.8		—		3.1
Thereafter	3.3		—		13.5
Total (a)	$	13.2	$	12.9	$	58.0

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

Future Commitments Under Operating Leases

Future commitments under operating leases are:

(Millions of Dollars)
2015	$	0.9
2016	0.9
2017	1.0
2018	1.0
2019	1.0
Thereafter	7.9
Total	$	12.7

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, 2014		Dec. 31, 2013
Current assets	$	246	$	223
Property, plant and equipment, net	2,278		2,427
Other noncurrent assets	122		112
Total assets	$	2,646	$	2,762
Current liabilities	$	1,349	$	233
Mortgages and other long-term debt payable	486		1,687
Other noncurrent liabilities	48		42
Total liabilities	$	1,883	$	1,962

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	$	0.2	2018	(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, 2014 and 2013 is as follows:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow Revisions		Ending Balance Dec. 31, 2014 (a)
Electric plant
Steam production asbestos	$	2,005	$	—	$	44	$	—	$	2,049
Steam and other 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 (b)	$	2,853	$	515	$	76	$	5,646	$	9,090

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

^(a)  There were no ARO liabilities settled during the years ended Dec. 31, 2014 or 2013.

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

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Joint Ownership of Transmission Facilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 26,434
Accumulated depreciation	8,082
Construction work in progress	113,754
CapX2020 Transmission | Electric Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	26,434
Accumulated depreciation	8,082
Construction work in progress	103,940
Ownership % (in hundredths)	80.70%
La Crosse, Wis. to Madison, Wis. | Electric Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	0
Accumulated depreciation	0
Construction work in progress	$ 9,814
Ownership % (in hundredths)	50.00%

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Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income and Expenses [Abstract]
Interest income	$ 368	$ 538	$ 736
Other nonoperating income	321	152	129
Insurance policy expense	(409)	(427)	(389)
Other nonoperating expense	(10)	(10)	0
Other income, net	$ 270	$ 253	$ 476

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) (Postretirement Benefit Plan)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Postretirement Health Care Benefits [Abstract]
Amortization period for unrecognized accumulated postretirement benefit obligation (in years)	20 years
Target pension asset allocations (in hundredths)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	25.00%	41.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	57.00%	40.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	13.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (in hundredths)	5.00%	6.00%