NORTHERN STATES POWER CO /WI/ - FORM 10-K

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EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO /WI/	nspwex3102q42015.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO /WI/	nspwex3101q42015.htm
EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO /WI/	nspwex9901q42015.htm
EX-23.01 - EXHIBIT 23.01 - NORTHERN STATES POWER CO /WI/	nspwex2301q42015.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO /WI/	nspwex3201q42015.htm
EX-12.01 - EXHIBIT 12.01 - NORTHERN STATES POWER CO /WI/	nspwex1201q42015.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2015



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

Commission file number 001-03140

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)



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

1414 West Hamilton Avenue, Eau Claire, Wisconsin 54701

(Address of principal executive offices)

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

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

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

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

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

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

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

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

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



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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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

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

TABLE OF CONTENTS

Index



PART I
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	7
Fuel Sources	8
Renewable Energy Sources	9
Summary of Recent Federal Regulatory Developments	9
Electric Operating Statistics	11
NATURAL GAS UTILITY OPERATIONS	12
Public Utility Regulation	12
Capability and Demand	13
Natural Gas Supply and Costs	13
Natural Gas Operating Statistics	14
GENERAL	14
ENVIRONMENTAL MATTERS	15
EMPLOYEES	15
Item 1A — Risk Factors	15
Item 1B — Unresolved Staff Comments	24
Item 2 — Properties	25
Item 3 — Legal Proceedings	25
Item 4 — Mine Safety Disclosures	26
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6 — Selected Financial Data	26
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	29
Item 8 — Financial Statements and Supplementary Data	29
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A — Controls and Procedures	73
Item 9B — Other Information	73
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	73
Item 11 — Executive Compensation	73
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	73
Item 13 — Certain Relationships and Related Transactions, and Director Independence	73
Item 14 — Principal Accountant Fees and Services	74
PART IV
Item 15 — Exhibits, Financial Statement Schedules	74
SIGNATURES	78

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

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS



Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries

Federal and State Regulatory Agencies
CFTC	Commodity Futures Trading Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
PGA	Purchased gas adjustment

Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
C&I	Commercial and Industrial
CAA	Clean Air Act
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CO₂	Carbon dioxide
CPCN	Certificate of public convenience and necessity
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
ITC	Investment tax credit
LNG	Liquefied natural gas

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MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
NAAQS	National Ambient Air Quality Standard
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NOL	Net operating loss
NOx	Nitrogen oxide
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PI	Prairie Island nuclear generating plant
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
REC	Renewable energy credit
ROE	Return on equity
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
SO₂	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services

Measurements
KV	Kilovolts
KWh	Kilowatt hours
Mcf	Thousand cubic feet
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is a utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in this service territory. NSP-Wisconsin provides electric utility service to approximately 256,000 customers and natural gas utility service to approximately 112,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2015. Although NSP-Wisconsin’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large commercial and industrial electric sales include the following industries: food products, paper, allied products and sand mining for oil and gas extraction. For small commercial and industrial customers, significant electric retail sales include the following industries: grocery and dining establishments, educational services and health services. Generally, NSP-Wisconsin’s earnings contribute approximately five percent to 10 percent of Xcel Energy’s consolidated net income.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

NSP-Wisconsin conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 14 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.

NSP-Wisconsin’s corporate strategy focuses on four core objectives: improving utility performance; driving operational excellence; improving customer experience; and investing for the future.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

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

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

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

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

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

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2016, assuming normal weather conditions, is as follows:



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

The peak demand for the NSP System typically occurs in the summer. The 2015 system peak demand for the NSP System occurred on Aug. 14, 2015. The 2015 system peak demand was lower due to cooler summer weather. The 2016 forecast assumes normal peak day weather.

Energy Sources and Related Transmission Initiatives

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

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

Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.

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

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


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


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


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


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


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


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

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

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

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

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line — In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. NSP-Wisconsin’s half of the line will be shared with three co-owners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.

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

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

Fuel Supply and Costs

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



	Coal ^(a)				Nuclear				Natural Gas				Weighted Average Owned Fuel Cost
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2015	$	2.15	47	%	$	0.83	40	%	$	3.89	13	%	$	1.85
2014	2.23		52		0.89		42		6.27		6		1.94
2013	2.20		49		0.95		40		5.08		11		2.03


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

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

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

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Fuel Sources

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

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 90 percent of their estimated coal requirements in 2016, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 90 percent of requirements for the first year, 60 percent of requirements in year two, and 30 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2016 and 2017. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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


•	Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 59 percent of the requirements for 2019 through 2030;


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


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

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

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

Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies, transportation and storage services for power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2015 and 2014, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $310 million and $349 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2016 to 2028.

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

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Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2015, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 12.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.


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


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


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


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

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

Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program. Over 1,458 PV systems with approximately 18.3 MW of aggregate capacity and over 915 PV systems with approximately 11.1 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2015 and 2014, respectively.

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


•	Collectively, the NSP System had approximately 2,210 and 1,860 MWs of wind energy on its system at the end of 2015 and 2014, respectively. In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.

•

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

Hydroelectric — The NSP System acquires its hydroelectric energy from both owned generation and PPAs. The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 277.5 MW of capacity. For 2015, PPAs provided approximately 34 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 725 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

Wholesale and Commodity Marketing Operations

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

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Summary of Recent Federal Regulatory Developments

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

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In March, 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any litigated ROE complaint proceedings until at least mid-2016. See Note 10 to the consolidated financial statements for discussion of the MISO ROE Complaints.

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

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

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

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

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Electric Operating Statistics

Electric Sales Statistics



	Year Ended Dec. 31
	2015			2014			2013
Electric sales (Millions of KWh)
Residential	1,863			1,984			1,990
Large commercial and industrial	1,868			1,823			1,698
Small commercial and industrial	2,877			2,902			2,837
Public authorities and other	39			42			36
Total retail	6,647			6,751			6,561
Sales for resale	—			—			1
Total energy sold	6,647			6,751			6,562

Number of customers at end of period
Residential	215,135			214,350			213,665
Large commercial and industrial	120			114			107
Small commercial and industrial	39,254			38,939			38,549
Public authorities and other	1,175			1,144			1,149
Total customers	255,684			254,547			253,470

Electric revenues (Thousands of Dollars)
Residential	$	244,417		$	254,277		$	247,081
Large commercial and industrial	141,007			136,435			125,151
Small commercial and industrial	284,427			282,016			267,796
Public authorities and other	6,576			6,636			6,184
Total retail	676,427			679,364			646,212
Interchange revenues from NSP-Minnesota	163,255			145,102			136,917
Other electric revenues	(4,684		)	5,282			6,039
Total electric revenues	$	834,998		$	829,748		$	789,168

KWh sales per retail customer	25,997			26,522			25,885
Revenue per retail customer	$	2,646		$	2,669		$	2,549
Residential revenue per KWh		13.12	¢		12.82	¢		12.42	¢
Large commercial and industrial revenue per KWh	7.55			7.48			7.37
Small commercial and industrial revenue per KWh	9.89			9.72			9.44
Total retail revenue per KWh	10.18			10.06			9.85

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Energy Source Statistics



	Year Ended Dec. 31
	2015			2014			2013
NSP System	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	15,961	35	%	18,079	39	%	15,844	36	%
Nuclear	12,425	27		13,434	29		12,161	28
Natural Gas	6,689	15		3,402	7		5,550	13
Wind ^(a)	6,235	14		6,243	14		5,481	13
Hydroelectric	3,326	7		3,560	8		3,223	7
Other ^(b)	1,083	2		1,417	3		1,323	3
Total	45,719	100	%	46,135	100	%	43,582	100	%

Owned generation	33,818	74	%	33,641	73	%	29,249	67	%
Purchased generation	11,901	26		12,494	27		14,333	33
Total	45,719	100	%	46,135	100	%	43,582	100	%


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


^(b)	Includes energy from other sources, including solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and was approximately eight, seven, and eight million net KWh for 2015, 2014, and 2013, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

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

The Pipeline and Hazardous Materials Safety Administration

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

Public Utility Regulation

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

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Natural Gas Cost-Recovery Mechanisms — NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin operations to recover the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds NSP-Wisconsin was not prudent in its procurement activities.

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

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 158,719 MMBtu, which occurred on Jan. 7, 2015, and 163,520 MMBtu, which occurred on Jan. 6, 2014.

NSP-Wisconsin purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 139,127 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 31 percent of winter natural gas requirements and 34 percent of peak day firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 12 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2015-2016 supply plan was approved by the PSCW in September 2015.

Natural Gas Supply and Costs

NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Wisconsin conducts natural gas price hedging activity that has been approved by the PSCW.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Wisconsin’s regulated retail natural gas distribution business:



2015	$	4.11
2014	6.52
2013	4.51

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

The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment mechanisms. NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2016 through 2029.

NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2015, NSP-Wisconsin was committed to approximately $55 million in such obligations under these contracts.

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

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

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Natural Gas Operating Statistics



	Year Ended Dec. 31
	2015		2014		2013
Natural gas deliveries (Thousands of MMBtu)
Residential	6,584		8,098		7,505
Commercial and industrial	9,116		10,626		10,131
Total retail	15,700		18,724		17,636
Transportation and other	4,756		4,729		4,344
Total deliveries	20,456		23,453		21,980

Number of customers at end of period
Residential	99,316		98,325		96,974
Commercial and industrial	12,902		12,773		12,646
Total retail	112,218		111,098		109,620
Transportation and other	25		23		23
Total customers	112,243		111,121		109,643

Natural gas revenues (Thousands of Dollars)
Residential	$	61,277	$	82,851	$	67,745
Commercial and industrial	55,677		82,181		63,896
Total retail	116,954		165,032		131,641
Transportation and other	3,193		4,597		1,226
Total natural gas revenues	$	120,147	$	169,629	$	132,867

MMBtu sales per retail customer	139.91		168.54		160.88
Revenue per retail customer	$	1,042	$	1,485	$	1,201
Residential revenue per MMBtu	9.31		10.23		9.03
Commercial and industrial revenue per MMBtu	6.11		7.73		6.31
Transportation and other revenue per MMBtu	0.67		0.97		0.28

GENERAL

Seasonality

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

Competition

NSP-Wisconsin is a vertically integrated utility, subject to traditional cost-of-service regulation. However, NSP-Wisconsin is subject to different public policies that promote competition and the development of energy markets. NSP-Wisconsin’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with solar generation (typically rooftop solar or solar gardens) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

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The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, NSP-Wisconsin can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. NSP-Wisconsin has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. While facing these challenges, NSP-Wisconsin believes its rates and services are competitive with currently available alternatives. As of Jan. 1, 2013 all of NSP-Wisconsin’s wholesale customers began purchasing power from an alternate supplier.

ENVIRONMENTAL MATTERS

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

There are significant present and future environmental regulations to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. NSP-Wisconsin has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. We believe, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2015, NSP-Wisconsin had 560 full-time employees and three part-time employees, of which 400 were covered under collective-bargaining agreements. See Note 7 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

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

Oversight of Risk and Related Processes

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

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

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At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone at the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups and overall business management to mitigate the risks inherent in the implementation strategy. Building on this culture of compliance, we manage and further mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services.

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

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

Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting but potentially more costly facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2015, these sites included:


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


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

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

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂, CO₂and other GHGs, particulates, cooling water intakes, water discharges and ash management. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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

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

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand may raise electricity prices, which would increase the cost of energy we provide to our customers.

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

Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of CO₂emissions under section 111(d) of the CAA, or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

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

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

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and there is no assurance that regulators would allow full recovery of all remaining costs. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.

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

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

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

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events and resulting broad financial market distress could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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

We are subject to credit risks.

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

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

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

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

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

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

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

Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Operational Risks

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

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

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

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

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

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

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


•	The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal and the current lack of a long-term disposal solution for radioactive materials;


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


•	Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. For example, similar to pensions, interest rate and other assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.

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

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

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

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

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

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

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

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

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

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

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

As of Dec. 31, 2015, Xcel Energy Inc. and its utility subsidiaries had approximately $12.5 billion of long-term debt and $1.5 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2015, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $12.5 million and exposure of $0.1 million. Xcel Energy also had additional guarantees of $41.3 million at Dec. 31, 2015 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy Inc. In 2015, 2014 and 2013 we paid $53.9 million, $43.8 million and $31.0 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.'s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Wisconsin is imposed by our state regulatory commission. NSP-Wisconsin cannot pay annual dividends in excess of certain amounts if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level. See Item 5 for further discussion on dividend limitations.

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Public Policy Risks

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

The EPA is regulating GHGs from power plants with state plans to achieve the EPA’s goals due by September 2018. Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International agreements could have an impact to the extent they lead to future federal or state regulations.

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

We have been, and in the future may be, subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates.

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

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

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO₂ and NOx, mercury, regional haze, ozone and particulate matter, water intakes, water discharges and ash management. The costs of investment to comply with these rules could be substantial and in some cases would lead to early retirement of coal units. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of up to $1 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations. If a serious reliability incident did occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance.

We attempt to mitigate the risk of regulatory penalties through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions. However, there is no guarantee our compliance program will be sufficient to ensure against violations.

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Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which is discussed in the capital market risk section above.

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

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

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities. Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, including NSP-Minnesota’s nuclear power plants under the NRC’s design basis threat requirements. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

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

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

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

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

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

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

Rising energy prices could negatively impact our business.

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

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

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

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

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



Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2015 Net Dependable Capability (MW)
Steam:
Bay Front-Ashland, Wis., 3 Units	Coal/Wood/Natural Gas	1948-1956	56
French Island-La Crosse, Wis., 2 Units	Wood/Refuse-derived fuel	1940-1948	16	^(a)
Combustion Turbine:
Flambeau Station-Park Falls, Wis., 1 Unit	Natural Gas	1969	12
French Island-La Crosse, Wis., 2 Units	Natural Gas	1974	122
Wheaton-Eau Claire, Wis., 4 Units	Natural Gas	1973	183
Hydro:
Various locations, 63 Units	Hydro	Various	135
		Total	524


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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2015:



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

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

Natural gas utility mains at Dec. 31, 2015:



Miles
Distribution	2,342

Item 3 — Legal Proceedings

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

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Additional Information

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

Item 4 — Mine Safety Disclosures

None.

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters 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:


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

•

The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission. NSP-Wisconsin cannot pay annual dividends during 2015 in excess of approximately $33.3 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements. NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 52.6 percent at Dec. 31, 2015 and $2.4 million in retained earnings was not restricted.

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

The dividends declared during 2015 and 2014 were as follows:



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

Item 6 — Selected Financial Data

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

Item 7 — Management’s 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.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 (including the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: : general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Wisconsin and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Wisconsin has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Wisconsin and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Results of Operations

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

Electric Revenues and Margin

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



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

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

Electric Revenues



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

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Electric Margin



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

Natural Gas Revenues and Margin

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



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

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

Natural Gas Revenues



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

Natural Gas Margin



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

Non-Fuel Operating Expenses and Other Items

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



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

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

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

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

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

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

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

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

Interest Rate Risk — NSP-Wisconsin is subject to the risk of fluctuating interest rates in the normal course of business. NSP-Wisconsin’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At Dec. 31, 2015 and 2014, a 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact annual pretax interest expense by approximately $0.1 million and $0.8 million, respectively. See Note 9 to the consolidated financial statements for a discussion of NSP-Wisconsin’s interest rate derivatives.

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

At Dec. 31, 2015 and 2014, a 10 percent increase or decrease in commodity prices would have an immaterial impact on credit exposure.

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

Item 8 — Financial Statements and Supplementary Data

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

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

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Management Report on Internal Controls Over Financial Reporting

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

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

NSP-Wisconsin management assessed the effectiveness of NSP-Wisconsin’s internal control over financial reporting as of Dec. 31, 2015. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2015, NSP-Wisconsin’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.



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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Northern States Power Company, a Wisconsin corporation

We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company, a Wisconsin corporation, and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, cash flows, and common stockholder’s equity for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company, a Wisconsin corporation, and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.



/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 22, 2016

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)



	Year Ended Dec. 31
	2015			2014			2013
Operating revenues
Electric	$	834,998		$	829,748		$	789,168
Natural gas	120,147			169,629			132,867
Other	1,396			1,085			1,003
Total operating revenues	956,541			1,000,462			923,038

Operating expenses
Electric fuel and purchased power, non-affiliates	10,795			19,595			18,129
Purchased power, affiliates	419,028			425,471			416,173
Cost of natural gas sold and transported	70,988			114,250			81,572
Operating and maintenance expenses	179,413			191,213			175,522
Conservation program expenses	11,695			11,537			12,333
Depreciation and amortization	91,245			79,654			76,897
Taxes (other than income taxes)	28,181			27,114			25,231
Loss on Monticello life cycle management/extended power uprate project	5,237			—			—
Total operating expenses	816,582			868,834			805,857

Operating income	139,959			131,628			117,181

Other income, net	883			270			253
Allowance for funds used during construction — equity	7,253			7,060			4,259

Interest charges and financing costs
Interest charges — includes other financing costs of $1,738, $1,570, and $1,538, respectively	32,731			29,273			27,797
Allowance for funds used during construction — debt	(3,510		)	(3,360		)	(1,981		)
Total interest charges and financing costs	29,221			25,913			25,816

Income before income taxes	118,874			113,045			95,877
Income taxes	44,238			42,403			36,409
Net income	$	74,636		$	70,642		$	59,468

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)



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

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)



	Year Ended Dec. 31
	2015			2014			2013
Operating activities
Net income	$	74,636		$	70,642		$	59,468
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	92,656			80,875			78,048
Deferred income taxes	45,833			45,396			25,789
Amortization of investment tax credits	(528		)	(527		)	(664		)
Allowance for equity funds used during construction	(7,253		)	(7,060		)	(4,259		)
Loss on Monticello life cycle management/extended power uprate project	5,237			—			—
Provision for bad debts	3,947			4,431			3,988
Net derivative losses (gains)	482			10			(279		)
Changes in operating assets and liabilities:
Accounts receivable	71			(5,558		)	(12,702		)
Accrued unbilled revenues	5,869			(1,933		)	(2,496		)
Inventories	3,126			(3,210		)	(1,879		)
Other current assets	7,135			(3,501		)	(3,749		)
Accounts payable	(7,626		)	2,936			(1,811		)
Net regulatory assets and liabilities	(27,114		)	(34,697		)	(2,062		)
Other current liabilities	5,147			(911		)	7,589
Pension and other employee benefit obligations	(3,177		)	(6,134		)	(8,759		)
Change in other noncurrent assets	209			(113		)	232
Change in other noncurrent liabilities	716			2,534			1,119
Net cash provided by operating activities	199,366			143,180			137,573

Investing activities
Utility capital/construction expenditures	(251,797		)	(288,209		)	(201,278		)
Allowance for equity funds used during construction	7,253			7,060			4,259
Other, net	(224		)	(166		)	(421		)
Net cash used in investing activities	(244,768		)	(281,315		)	(197,440		)

Financing activities
Proceeds from (repayments of) short-term borrowings, net	(68,000		)	10,000			29,000
Proceeds from notes payable to affiliates	—			30			—
Repayments of notes payable to affiliates	—			—			(80		)
Proceeds from issuance of long-term debt	97,969			98,534			—
Repayments of long-term debt	(87		)	(107		)	(160		)
Capital contributions from parent	69,243			73,432			58,977
Dividends paid to parent	(53,929		)	(43,818		)	(30,980		)
Net cash provided by financing activities	45,196			138,071			56,757

Net change in cash and cash equivalents	(206		)	(64		)	(3,110		)
Cash and cash equivalents at beginning of period	1,285			1,349			4,459
Cash and cash equivalents at end of period	$	1,079		$	1,285		$	1,349

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(27,491	)	$	(24,442	)	$	(24,376	)
Cash received (paid) for income taxes, net	5,762			3,474			(9,842		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	16,729		$	35,267		$	27,222

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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



	Dec. 31
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	1,079		$	1,285
Accounts receivable, net	56,378			60,396
Accrued unbilled revenues	47,698			53,567
Inventories	21,559			24,685
Regulatory assets	16,146			20,036
Prepaid taxes	25,976			28,628
Deferred income taxes	3,138			8,201
Prepayments and other	2,387			6,918
Total current assets	174,361			203,716

Property, plant and equipment, net	1,828,079			1,674,281

Other assets
Regulatory assets	289,196			280,693
Other investments	4,042			3,818
Other	5,211			4,612
Total other assets	298,449			289,123
Total assets	$	2,300,889		$	2,167,120

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,131		$	1,235
Short-term debt	10,000			78,000
Notes payable to affiliates	500			500
Accounts payable	34,317			61,530
Accounts payable to affiliates	24,538			26,524
Dividends payable to parent	15,322			14,957
Regulatory liabilities	11,781			16,940
Environmental liabilities	17,155			29,116
Accrued interest	7,945			7,658
Other	15,778			12,265
Total current liabilities	138,467			248,725

Deferred credits and other liabilities
Deferred income taxes	393,569			348,180
Deferred investment tax credits	8,560			9,089
Regulatory liabilities	141,289			132,674
Environmental liabilities	77,441			78,620
Customer advances	18,480			17,623
Pension and employee benefit obligations	49,889			51,313
Other	16,347			16,151
Total deferred credits and other liabilities	705,575			653,650

Commitments and contingencies
Capitalization
Long-term debt	666,462			567,056
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2015 and 2014, respectively	93,300			93,300
Additional paid in capital	394,553			322,276
Retained earnings	302,741			282,398
Accumulated other comprehensive loss	(209		)	(285		)
Total common stockholder’s equity	790,385			697,689
Total liabilities and equity	$	2,300,889		$	2,167,120

See Notes to Consolidated Financial Statements

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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			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
Balance at Dec. 31, 2012	933,000	$	93,300	$	189,867	$	234,376		$	(437	)	$	517,106
Net income						59,468						59,468
Other comprehensive income									76			76
Common dividends declared to parent						(31,345		)				(31,345		)
Contribution of capital by parent				58,977								58,977
Balance at Dec. 31, 2013	933,000	$	93,300	$	248,844	$	262,499		$	(361	)	$	604,282
Net income						70,642						70,642
Other comprehensive income									76			76
Common dividends declared to parent						(50,743		)				(50,743		)
Contribution of capital by parent				73,432								73,432
Balance at Dec. 31, 2014	933,000	$	93,300	$	322,276	$	282,398		$	(285	)	$	697,689
Net income						74,636						74,636
Other comprehensive income									76			76
Common dividends declared to parent						(54,293		)				(54,293		)
Contribution of capital by parent				72,277								72,277
Balance at Dec. 31, 2015	933,000	$	93,300	$	394,553	$	302,741		$	(209	)	$	790,385

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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



	Dec. 31
	2015			2014
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
June 15, 2024, 3.3%	200,000			100,000
Sept. 1, 2038, 6.375%	200,000			200,000
Oct. 1, 2042, 3.7%	100,000			100,000
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% ^(a)	18,600			18,600
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%	490			523
Other	1,634			1,687
Unamortized discount	(3,131		)	(2,519		)
Total	667,593			568,291
Less current maturities	1,131			1,235
Total long-term debt	$	666,462		$	567,056
Common Stockholder’s Equity
Common stock — 1,000,000 shares authorized of $100 par value;
933,000 shares outstanding at Dec. 31, 2015 and 2014, respectively	$	93,300		$	93,300
Additional paid in capital	394,553			322,276
Retained earnings	302,741			282,398
Accumulated other comprehensive loss	(209		)	(285		)
Total common stockholder’s equity	$	790,385		$	697,689


^(a)	Resource recovery financing

See Notes to Consolidated Financial Statements

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Notes to Consolidated Financial Statements


1.	Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Wisconsin has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin's proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin's proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages.

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

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

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


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


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

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

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

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

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NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically, for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.

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

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

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment that is required to be decommissioned early by a regulator is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.4, 3.3 and 3.5 percent for the years ended Dec. 31, 2015, 2014 and 2013, respectively.

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

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

Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.

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AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.

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

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize only applies to federal ITCs. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

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

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

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

See Note 6 for further discussion of income taxes.

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

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

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

See Note 11 for further discussion of environmental costs.

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

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

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

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

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

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2015 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.


2.	Accounting Pronouncements

Recently Issued

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

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

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

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

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

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


3.	Selected Balance Sheet Data



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


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



(Thousands of Dollars)	Dec. 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	6,785	$	6,494
Fuel	6,528

NORTHERN STATES POWER CO /WI/ - FORM 10-K - February 22, 2016

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