UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

(Exact name of registrant as specified in its charter)

(Address of principal executive offices)

Index

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.

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin.  NSP-Wisconsin is a utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan.  NSP-Wisconsin purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in this service territory.  NSP-Wisconsin provides electric utility service to approximately 253,000255,000 customers and natural gas utility service to approximately 110,000111,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2013.2014.  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 and sand mining.extraction.  For small commercial and industrial customers, significant electric retail sales include the following industries:  grocery and dining establishments, educational services and food products.health services.  Generally, NSP-Wisconsin’s earnings contribute approximately 5five 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; and enhancing engagement with employees, customers, shareholders, communities and policy makers.  NSP-Wisconsin files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.  Environmental leadership is a core priority for NSP-Wisconsin and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.future.

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.

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

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2014,2015, assuming normal weather, is listed below.

The peak demand for the NSP System typically occurs in the summer. The 20132014 uninterrupted system peak demand for the NSP System occurred on Aug. 26, 2013.July 21, 2014. The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted2014 system peak demand since July 31, 2006.was lower due to cooler summer weather. The 2012 peak demand occurred uninterrupted on a day with weather much closer to normal peak day conditions. The 2013 peak demand includes the effect of warmer weather partially offset by the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin and also reflects the impact of two large commercial and industrial customers at NSP-Minnesota that have ceased operations. These two large customers represented 1.3 percent, 0.4 percent, and zero percent of NSP System sales in 2011, 2012, and 2013 respectively. The 20142015 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.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line — In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, also known as the Badger Coulee line, would run between 159154 and 182187 miles based on the permitted route, which includes AFUDC, of between $540 and cost between $514$580 million. NSP-Wisconsin’s half of the project is shared with two partners, Dairyland Power Cooperative and $552 million, depending upon the route ultimately approved by the PSCW.WPPI Energy. NSP-Wisconsin’s shareportion of the investment is estimated to be between $230$190 and $247$207 million. The cost estimates are based on a projected 2018 in-service year. In December 2011, MISO determined the line to be ana MVP project, and as such, eligible for cost sharing under MISO’s MVP tariff.

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.

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

Fuel Sources

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 9488 percent of their estimated coal requirements in 2014,2015, 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 followingfirst year, 67 percent of requirements in year two, years, and 33 percent of requirements in three years.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 20142015 and 2015.2016. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Fabrication services for Monticello and Prairie IslandPI are 100 percent committed through 20272030 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.

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

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2013,2014, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 8.8912.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.

The NSP System also offers customer-focused renewable energy initiatives. Windsource®, one of the nation’s largest voluntary renewable energy programs, allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources. In 2013,2014, the number of customers utilizing Windsource increased to approximately 43,000 from 37,000 from 24,000 in 2012.2013. Windsource MWh sales declined slightly due to the loss of a large commercial participantincreased from approximately 184,000 MWh in 2012 to 181,000 MWh in 2013. 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 679915 PV systems with approximately 7.311.1 MW of aggregate capacity and over 561679 PV systems with approximately 6.37.3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 20132014 and 2012,2013, respectively.

Wind — The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota.The Currently, the NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW. 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. Two of theOne additional 20 MW project was approved in 2014. All five projects the Pleasant Valley wind farm in Minnesota and the Border Winds wind farm in North Dakota are expectedtargeted to be operational byin 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 thesethe existing contracts was approximately $41 for 20132014 and 2012.2013. 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 20132014 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2013.2014, 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 274268 MW of capacity. For 2013, there were nine2014, PPAs in place which provided approximately 3738 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.

MISO has submitted multiple compliance filings with the FERC to implement the Order 1000 final rulesrequirements. 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 D.C. Circuit. NSP-Wisconsin is participatingremoval of federal ROFR provisions from individual contracts or tariffs could be considered in theindividual 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 in coordination with other MISO transmission owners and utilities who oppose certain aspects of the rules, including the ROFR prohibition. Briefs have been filed by parties challenging the final rules, and by the FERC and by parties supporting the final rules. Oral arguments are scheduled for March 20, 2014. The date for a Court ruling is uncertain.

Order 1000 could create opportunities for third parties to build suchand own certain regional transmission projects would extend to competitivethat had previously been reserved for the MISO transmission developers.  Compliance withowners, potentially reducing NSP-Wisconsin’s financial return on new investments in electric transmission facilities. The ultimate impact of Order 1000 foron future NSP-Wisconsin will occur through changes to the MISO tariff.  MISO made its initial compliance filings to incorporate new provisions into its tariff regarding regional planning and cost allocation.transmission investment is not known at this time.

Xcel Energy Services Inc. and NSP-Wisconsin vs. ATCAmerican 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, (alsoalso known as the Badger Coulee line)line, belong equally to NSP-Wisconsin and American Transmission Company, LLC (ATC).ATC. In August 2012, ATC requested rehearing and requested that the FERC grant a stay of the ruling. In September 2012, the FERC granted rehearing for purposes of further consideration but did not grantATC and NSP-Wisconsin jointly filed a stay.  Thus, the July ruling remains in effect pending the FERC’s further ruling on rehearing.  In order to proceed with development of the project, the two companies are working together on routing and regulatory state issues pending FERC action on ATC’s request for rehearing. A joint CPCN application was filed with the PSCW for the project in October 2013.

Overview

The most significant developments in the natural gas operations of NSP-WisconsinNSP‑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 2013,2014, average annual sales to the typical NSP-WisconsinNSP‑Wisconsin residential customer declined 1615 percent, andwhile sales to the typical small commercial and industrialC&I customer increased 710 percent, each on a weather-normalized basisbasis. 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

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.

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, and 143,134 MMBtu, which occurred on Jan. 19, 2012.2013.

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 132,591131,857 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 2631 percent of winter natural gas requirements and 3934 percent of peak day firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2013-20142014-2015 supply plan was approved by the PSCW in November 2013.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:

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 20142015 through 2029.

NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2013,2014, NSP-Wisconsin was committed to approximately $82$71 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 138 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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

GENERAL

Seasonality

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

Competition

NSP-Wisconsin remainsis a vertically integrated utility, subject to traditional cost-of-service regulation. Within this construct, however,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.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, NSP-Wisconsin and its wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. In addition, FERC Order 1000 seeks to establish competition for construction and operation of 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’sNSP-Wisconsin believes its rates and services are competitive with currently available alternatives. NSP-Wisconsin continues to evaluate policies, products and strategies to enable it to compete in the changing energy marketplace. As of Jan. 1, 2013 all of NSP-Wisconsin’s wholesale customers began purchasing power from an alternate supplier.

ENVIRONMENTAL MATTERS

NSP-Wisconsin’s facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. NSP-Wisconsin has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. NSP-Wisconsin’s facilities have been designed and constructed to operate in compliance with applicable environmental standards. NSP-Wisconsin strives to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon NSP-Wisconsin’s operations. See Notes 10 and 11 to the consolidated financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. While environmental regulations related to climate change and clean energy continue to evolve, NSP-Wisconsin has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. AlthoughIf these future environmental regulations do not provide credit for the impact of these policies on NSP-Wisconsin will depend on the specifics of state and federal policies, legislation, and regulation,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, that, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2013,2014, NSP-Wisconsin had 568567 full-time employees and fourthree part-time employees, of which 399402 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.

The goalA key accountability of Xcel Energy’s risk management process, which includes NSP-Wisconsin, is to understand, manage and, when possible, mitigate material risk. Management is responsible for identifying and managing risks, while the Board of Directors overseesis to identify, manage and holdsmitigate material risk. Our Board employs an effective process for doing so, combining management accountable.  NSP-Wisconsin is faced with a numberand Board risk oversight. The guidelines on corporate governance and Board committee charters define the scope of different typesreview 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.  Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy Inc.’s and NSP-Wisconsin’s senior management.  Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.of the risk.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Managementcontrollability, broadly considersconsidering our business, the utility industry, the domestic and global economy and the environment to identify risks.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.

At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone at the risks inherent in the implementation of Xcel Energy Inc.’s and NSP-Wisconsin’s strategy.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.  At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone atmanagement to mitigate the top, which mitigates risk.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.  While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

Management communicates regularly with Xcel Energy Inc.’sthe Board and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board in presentations and communications over the course of the year.

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

Risks Associated with Our Business

Environmental Risks

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards.  Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2013,2014, these sites included:

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial position or cash flows.

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

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

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.

Financial Risks

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.

OurThe 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.

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.

Utility operations require significant capital investment in property, plant and equipment; consequently,equipment. As a result, we are an active participant infrequently 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.

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,liquidity. However, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC has granted an increaseCFTC’s rules permit us to deal in the de minimis level for swap transactionsutility operations-related swaps with defined utility special entities generally entities owning or operating electric or natural gas facilities, fromand 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 to $800 million.for the preceding 12 months. Our current level of financial swap activity with special entities is significantly below this newspecial entity de minimis threshold; therefore, we will not be classified as a swap dealer in our special entity activity. Swap transactions with non specialnon-special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act. We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

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

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

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  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 engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. As a result we are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility.. Actual settlements can vary significantly from these estimates,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.

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.

NSP-Minnesota’s two nuclear stations, Prairie IslandPI and Monticello, subject it to the risks of nuclear generation, which include:

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

In some of our state jurisdictions,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; howeverfuture. 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 activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, weWe maintain insurance against some, but not all, of these risks and losses.

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

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

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

As of Dec. 31, 2013,2014, Xcel Energy Inc. and its utility subsidiaries had approximately $10.9$11.5 billion of long-term debt and $1.0$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, 2013,2014, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19.4$13.9 million and $0.3$0.2 million of exposure. Xcel Energy also had additional guarantees of $32.1$31.4 million at Dec. 31, 20132014 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.

All of the members of our boardBoard of directors,Directors, as well as many of our executive officers, are officers of Xcel Energy Inc.  Our boardBoard 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 2012 and 20112012 we paid $43.8 million, $31.0 million $57.3 million and $32.9$57.3 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our boardBoard of directorsDirectors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of certain amounts if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level. See Item 5 for further discussion on dividend limitations.

Public Policy Risks

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change.  Such legislativeLegislative 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 adopted new permitting requirements forhas proposed regulations to reduce GHG emissions of new and modified large stationary sources, which are applicable to construction of newfrom existing power plants or power plant modifications that increase emissions above a certain threshold.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.built which may be adopted in 2015. If adopted, these regulations could significantly increase the cost of building new generating plants. By 2016,

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 maywill be enacted.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 multipleother sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are recognized as compliance options, the allocation ofhow any emission allowances would be allocated to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., anyIn 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 that are ultimately imposed.  We may not be able toin a timely recover all costs related to complying with regulatory requirements imposed on us.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.

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.

The FERC issued NOVs of its market manipulation rules to several market participants during 2013.  The potential penalties in one pending case exceed $400 million.  We attempt to mitigate thisthe 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.

Macroeconomic Risks

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 generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business.  We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, including NSP-Minnesota’s nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel.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.

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

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (e.g., information about our customers, employees, operations, infrastructure and assets) could be directly or indirectly affected by unintentional or deliberate cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States, and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to liability. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations,  could also negatively impact our business.  In addition, we also anticipate that such an event would likely receive regulatory scrutiny at both the Federalfederal and Statestate level. We are unable to quantify the potential impact of such cyber security threats or subsequent related actions.  These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may cause significant 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.

HigherWhile we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if requests for recoverycosts are unsuccessful.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 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.

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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2013:2014:

NSP-Wisconsin had 203201 electric utility transmission and distribution substations at Dec. 31, 2013.2014.

Natural gas utility mains at Dec. 31, 2013:2014:

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.

None.

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

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

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

The dividends declared during 20132014 and 20122013 were as follows:

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

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Wisconsin and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow downslowdown 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.

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:

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

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:

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

Non-Fuel Operating Expenses and Other Items

AFUDC, Equity and Debt — AFUDC increased $2.3$4.2 million for 20132014 compared with 2012.2013. The increase is primarily due to the expansion of transmission facilities.

Derivatives, Risk Management and Market Risk

In the normal course of business, NSP-Wisconsin is exposed to a variety of market risks.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.

At Dec. 31, 20132014 and 2012,2013, a 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact annual pretax interest expense annually by approximately $0.7$0.8 million and $0.4$0.7 million, respectively.  See Note 9 to the consolidated financial statements for a discussion of NSP-Wisconsin’s interest rate derivatives.

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

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

Item 8 — Financial Statements and Supplementary Data

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

See Note 16 to the consolidated financial statements for summarized quarterly financial data.

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.

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, 20132014 and 2012,2013, 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, 2013.2014.  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'sCompany’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.