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EX-99.01 - EXHIBIT 99.01 - NORTHERN STATES POWER CO /WI/nspwex9901q42016.htm
EX-32.01 - EXHIBIT 32.01 - NORTHERN STATES POWER CO /WI/nspwex3201q42016.htm
EX-31.02 - EXHIBIT 31.02 - NORTHERN STATES POWER CO /WI/nspwex3102q42016.htm
EX-31.01 - EXHIBIT 31.01 - NORTHERN STATES POWER CO /WI/nspwex3101q42016.htm
EX-23.01 - EXHIBIT 23.01 - NORTHERN STATES POWER CO /WI/nspwex2301q42016.htm
EX-12.01 - EXHIBIT 12.01 - NORTHERN STATES POWER CO /WI/nspwex1201q42016.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, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-03140
NORTHERN STATES POWER COMPANY
(Exact name of registrant as specified in its charter)
Wisconsin
 
39-0508315
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)

1414 West Hamilton Avenue, Eau Claire, Wisconsin 54701
(Address of principal executive offices)

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

Securities registered pursuant to Section 12(b) of the Act:  None
Securities registered pursuant to section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
 
Accelerated filer ¨
Non-accelerated filer x
 
Smaller Reporting Company ¨
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  ¨ Yes x No
As of Feb. 24, 2017, 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 2017 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 4, 2017. 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
 
PART II
 
PART III
 
PART IV
 
SIGNATURES

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.

2


PART I
Item lBusiness

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
DOC
Minnesota Department of Commerce
DOE
United States Department of Energy
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
NDPSC
North Dakota Public Service Commission
NERC
North American Electric Reliability Corporation
NRC
Nuclear Regulatory Commission
PHMSA
Pipeline and Hazardous Materials Safety Administration
PSCW
Public Service Commission of Wisconsin
SDPUC
South Dakota Public Utilities Commission
SEC
Securities and Exchange Commission
 
 
Electric, Purchased Gas and Resource Adjustment Clauses
CIP
Conservation improvement program
EPU
Extended power uprate
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
CON
Certificate of need
CPCN
Certificate of public convenience and necessity
CPP
Clean Power Plan
CSAPR
Cross-State Air Pollution Rule

3


CWIP
Construction work in progress
ERCOT
Electric Reliability Council of Texas
ETR
Effective tax rate
FASB
Financial Accounting Standards Board
GAAP
Generally accepted accounting principles
GHG
Greenhouse gas
ITC
Investment tax credit
LCM
Life cycle management
LNG
Liquefied natural gas
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
NAV
Net asset value
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
R&E
Research and experimentation
REC
Renewable energy credit
ROE
Return on equity
RPS
Renewable portfolio standards
RTO
Regional Transmission Organization
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool, Inc.
Standard & Poor’s
Standard & Poor’s Ratings Services
TO
Transmission owner
 
 
Measurements
GWh
Gigawatt hours
KV
Kilovolts
KWh
Kilowatt hours
Mcf
Thousand cubic feet
MMBtu
Million British thermal units
MW
Megawatts
MWh
Megawatt hours


4


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 257,000 customers and natural gas utility service to approximately 113,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2016 and 2015. Although NSP-Wisconsin’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large C&I electric sales include the following industries: food products, paper, allied products and petroleum pipelines. For small C&I 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.

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 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.


5


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 2017, assuming normal weather conditions, is as follows:
 
System Peak Demand (in MW)
 
2014
 
2015
 
2016
 
2017 Forecast
NSP System
8,848

 
8,621

 
9,002

 
9,179


The peak demand for the NSP System typically occurs in the summer. The 2016 system peak demand for the NSP System occurred on July 20, 2016. The 2016 system peak demand increased from the previous year due to customer growth and warmer summer weather. The 2017 forecast assumes normal peak day weather, which would be warmer than 2016.

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 require a periodic payment and a charge for the delivered associated energy. Some long-term purchased power contracts only 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 2017, the MPUC approved NSP-Minnesota’s Integrated Resource Plan that includes:

Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026. The resulting need for 750 MW of capacity in 2026 will be addressed in a future CON proceeding;
Acquisition of at least 1,000 MW of wind by 2019 and possibly as much as 1,500 MW dependent on price, bidder qualifications, rate impact, transmission availability and location. The mix of purchased power and owned facilities was not specified;
Acquisition of 650 MW of solar by 2021 either through the community solar gardens program or other cost-effective resources. The mix of purchased power and owned facilities was not specified;
Acquisition of at least 400 MW of additional demand response by 2023, and a study of the technical and economic achievability of 1,000 MW of additional demand response in total by 2025; and
Achievement of at least 444 GWh of energy efficiency in all planning years.

In 2016, Minnesota legislators introduced a bill which would allow NSP-Minnesota to build a natural gas combined-cycle power plant at NSP-Minnesota’s Sherco site. The bill passed the House and Senate in February 2017 but will require approval from the Governor to become effective. A final resolution is expected later in 2017 and cost recovery would be subject to MPUC approval.

Request for Proposal (RFP) In September 2016, NSP-Minnesota issued a RFP for 1,500 MW of wind generation.  The RFP requests both PPAs and build-own-transfer proposals.

In October 2016, NSP-Minnesota submitted a petition for approval to the MPUC of a 750 MW self-build wind farm portfolio. RFP bids were received in October 2016 and have been evaluated in conjunction with the self-build proposal.


6


In January 2017, NSP-Minnesota completed the bid evaluation process. NSP-Minnesota evaluated the bid proposals based on a completeness review, a levelized cost of electricity economic evaluation and a non-price qualitative review. NSP-Minnesota believes its self-build wind projects were competitive and should complement the RFP portfolio.

An overview of the anticipated RFP schedule is as follows:

Project proposal selection and negotiation during the first quarter of 2017;
NSP-Minnesota’s recommendation for proposed wind additions to the MPUC later in the first quarter of 2017; and
MPUC approval is expected by July 2017.

CapX2020 — The estimated cost of the five major CapX2020 transmission projects is $2 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.06 billion of the total investment and the majority of this investment has occurred.

The Wisconsin portion of the Hampton, Minnesota to La Crosse, Wisconsin 161/345 KV transmission line included a new substation and approximately 50 miles of new 345 KV transmission line, at an estimated cost of $211 million. The final 161 KV and 345 KV segments of the project went into service in January 2016 and September 2016, respectively.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse to Madison, Wis. Transmission Line — In 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 2015, the PSCW issued its order approving a CPCN and route for the project. Subsequently, the PSCW denied two requests for rehearing. Two groups have appealed the CPCN Order to county circuit court. Court action is pending in one remaining appeal 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 $541 million. NSP-Wisconsin’s portion of the investment, which includes AFUDC, is estimated to be approximately $200 million. Updated forecast costs are primarily due to better material pricing than originally anticipated. Construction on the line began in January 2016, with completion anticipated by late 2018.

2016 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the year ended Dec. 31, 2016 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 sales volume and lower purchased power costs coupled with moderate weather. Under the fuel cost recovery rules, NSP-Wisconsin may retain the amount of over-recovery up to two percent of authorized annual fuel costs, or approximately $3.4 million. However, NSP-Wisconsin must defer the amount of over-recovery in excess of the two percent annual tolerance band for future refund to customers. Accordingly, NSP-Wisconsin recorded a deferral of approximately $9.8 million through Dec. 31, 2016. In March 2017 NSP-Wisconsin will file a reconciliation of 2016 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-2017.

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
 
2016
 
$
2.03

 
42
%
 
$
0.80

 
44
%
 
$
3.30

 
14
%
 
$
1.67

2015
 
2.15

 
47

 
0.83

 
40

 
3.89

 
13

 
1.85

2014
 
2.23

 
52

 
0.89

 
42

 
6.27

 
6

 
1.94


(a) 
Includes refuse-derived fuel and wood.

The cost of natural gas in 2016 decreased due to lower wholesale commodity prices.

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


7


Fuel Sources

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 2019 and approximately 53 percent of the requirements for 2020 through 2030;
Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 49 percent of the requirements for 2022 through 2030; and
Current enrichment service contracts cover 100 percent of the requirements through 2025 and approximately 28 percent of the requirements for 2026 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.

Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2016 and 2015 were approximately 55 and 67 days of usage, respectively. At Dec. 31, 2016, milder weather, purchase commitments and relatively low natural gas prices 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 2016 and 2015, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.5 million tons and 8.3 million tons, respectively. Coal requirements for 2016 decreased primarily due to relatively low natural gas prices during the year. The estimated coal requirements for 2017 are approximately 8.9 million tons. The increase is primarily due to higher expected natural gas prices in 2017.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 74 percent of their estimated coal requirements in 2017 and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 80 percent of requirements for the first year, 50 percent of requirements in year two and 25 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 2017 and 2018. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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, 2016 and 2015, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $382 million and $276 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2017 to 2028.

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


8


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, 2016, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18.0 percent and 12.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.

Renewable energy comprised 26.1 percent and 23.3 percent of the NSP System’s total energy for 2016 and 2015, respectively;
Wind energy comprised 16.4 percent and 13.6 percent of the total energy for 2016 and 2015, respectively;
Hydroelectric energy comprised 6.6 percent and 7.3 percent of the total energy for 2016 and 2015, respectively; and
Biomass and solar power comprised approximately 3.1 percent and 2.4 percent of the total energy for 2016 and 2015, 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 2016, the number of customers utilizing Windsource increased to approximately 54,000 from 50,000 in 2015.

Additionally, the Solar*Connect Community program is an option made available to encourage use of solar energy in Wisconsin. This program allows for offsite development of solar and bill credits to customers based on an approved tariffed rate. Two solar garden sites are currently in development and are anticipated to be on line in 2017.

Wind  The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota. Currently, the NSP System has more than 125 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 five wind farms which have the capacity to generate 852 MW.

The NSP System had approximately 2,602 and 2,210 MW of wind energy on its system at the end of 2016 and 2015, 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 existing contracts was approximately $43 and $42 for 2016 and 2015, 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 2016 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 2016, 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 also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates. See Item 7 for further discussion.


9


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.

Status of FERC Commissioners — The FERC is comprised of five commissioners appointed by the President and subject to confirmation by the Senate. There are today only two sitting commissioners.  It is uncertain when the President will appoint new commissioners to the open seats or when those appointments may be confirmed.  Without three sitting commissioners, the FERC will not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and CPCNs for construction of interstate natural gas pipeline facilities.    

FERC Order, ROE Policy — The FERC has adopted a two-step ROE methodology for electric utilities. The issue of how to apply the FERC ROE methodology is being contested in various complaint proceedings. There are two ROE complaints against the MISO TOs, which includes NSP-Wisconsin. In September 2016, the FERC issued an order in the first MISO ROE complaint, which upheld the initial decision made by the ALJ in December 2015, establishing an ROE of 10.32 percent for the period Nov. 12, 2013 to Feb. 11, 2015, and prospectively. The second complaint is pending FERC action after issuance of an initial decision by the ALJ in June 2016, recommending an ROE of 9.7 percent for the period Feb. 12, 2015 to May 11, 2016. The FERC is expected to issue an order in the second litigated MISO ROE complaint proceeding during 2017. 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. NSP-Wisconsin applied the requirements to high and medium impact assets by the July 1, 2016 deadline. Requirements must be applied to low impact assets through a staggered implementation beginning April 1, 2017 through September 2018. NSP-Wisconsin is currently in the process of implementing initiatives to meet the compliance deadline. The additional cost for compliance is anticipated to be recoverable through rates.

NERC Physical Security Requirements — In 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 developed physical security plans in accordance with the requirements of the standard. The additional cost for compliance is anticipated to be recoverable through rates.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, NSP-Minnesota and NSP-Wisconsin filed changes to their NSP System transmission formula rate to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filing was intended to ensure that NSP-Minnesota and NSP-Wisconsin are in compliance with IRS rules and may continue to use accelerated tax depreciation. NSP-Minnesota and NSP-Wisconsin requested a Jan. 1, 2016 effective date.

In 2015, the FERC partially accepted and partially rejected the proposed transmission formula rate changes. In September 2016, the FERC clarified its order, but required NSP-Minnesota and NSP-Wisconsin to submit a new tariff change filing to implement the treatment of ADIT in the formula rate true-up. In November 2016, NSP-Minnesota and NSP-Wisconsin filed the changes proposing a Jan. 1, 2017 effective date, but requesting authority to calculate the 2016 true-up pursuant to the new ADIT tariff provisions. In December 2016, the FERC issued an order which approved the tariff revisions, effective Jan. 1, 2017, but rejected the portion of its application related to the 2016 true-up. NSP-Minnesota and NSP-Wisconsin believe their wholesale formula rates are in compliance with the IRS ADIT rules.


10


Electric Operating Statistics

Electric Sales Statistics
 
Year Ended Dec. 31
 
2016
 
2015
 
2014
Electric sales (Millions of KWh)
 
 
 
 
 
Residential
1,868

 
1,863

 
1,984

Large commercial and industrial
1,885

 
1,868

 
1,823

Small commercial and industrial
2,856

 
2,877

 
2,902

Public authorities and other
32

 
39

 
42

Total energy sold
6,641

 
6,647

 
6,751

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
216,426

 
215,135

 
214,350

Large commercial and industrial
117

 
120

 
114

Small commercial and industrial
39,529

 
39,254

 
38,939

Public authorities and other
1,142

 
1,175

 
1,144

Total customers
257,214

 
255,684

 
254,547

 
 
 
 
 
 
Electric revenues (Thousands of Dollars)
 
 
 
 
 
Residential
$
248,476

 
$
244,417

 
$
254,277

Large commercial and industrial
142,942

 
141,007

 
136,435

Small commercial and industrial
287,060

 
284,427

 
282,016

Public authorities and other
6,105

 
6,576

 
6,636

Total retail
684,583

 
676,427

 
679,364

Interchange revenues from NSP-Minnesota
170,483

 
163,255

 
145,102

Other electric revenues
(5,120
)
 
(4,684
)
 
5,282

Total electric revenues
$
849,946

 
$
834,998

 
$
829,748

 
 
 
 
 
 
KWh sales per retail customer
25,819

 
25,997

 
26,552

Revenue per retail customer
$
2,662

 
$
2,646

 
$
2,669

Residential revenue per KWh

13.30
¢
 

13.12
¢
 

12.82
¢
Large commercial and industrial revenue per KWh
7.58

 
7.55

 
7.48

Small commercial and industrial revenue per KWh
10.05

 
9.89

 
9.72

Total retail revenue per KWh
10.31

 
10.18

 
10.06





11


Energy Source Statistics
 
Year Ended Dec. 31
 
2016
 
2015
 
2014
NSP System
Millions of KWh
 
Percent of
Generation
 
Millions of KWh
 
Percent of
Generation
 
Millions of KWh
 
Percent of
Generation
Nuclear
14,191

 
30
%
 
12,425

 
27
%
 
13,434

 
29
%
Coal
13,681

 
28

 
15,961

 
35

 
18,079

 
39

Wind (a)
7,897

 
16

 
6,235

 
14

 
6,243

 
14

Natural Gas
7,810

 
16

 
6,689

 
15

 
3,402

 
7

Hydroelectric
3,203

 
7

 
3,326

 
7

 
3,560

 
8

Other (b)
1,480

 
3

 
1,083

 
2

 
1,417

 
3

Total
48,262

 
100
%
 
45,719

 
100
%
 
46,135

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
36,381

 
75
%
 
33,818

 
74
%
 
33,641

 
73
%
Purchased generation
11,881

 
25

 
11,901

 
26

 
12,494

 
27

Total
48,262

 
100
%
 
45,719

 
100
%
 
46,135

 
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 21, eight and seven million net KWh for 2016, 2015, and 2014, 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 2016, average annual sales to the typical NSP‑Wisconsin residential customer declined 20 percent, while sales to the typical small C&I customer declined 2 percent, each on a weather-normalized basis. 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

The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act), signed into law in January 2012, 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 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. NSP-Wisconsin is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. NSP-Wisconsin cannot predict the ultimate impact the Pipeline Safety Act will have on its costs, operations or financial results.

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.


12


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 155,583 MMBtu, which occurred on Jan. 18, 2016, and 158,719 MMBtu, which occurred on Jan. 7, 2015.

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 140,143 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 32 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 2016-2017 supply plan was approved by the PSCW in October 2016.

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:
2016
$
3.62

2015
4.11

2014
6.52


The cost of natural gas in 2016 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 2017 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, 2016, NSP-Wisconsin was committed to approximately $103 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately nine 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.


13


Natural Gas Operating Statistics
 
Year Ended Dec. 31
 
2016
 
2015
 
2014
Natural gas deliveries (Thousands of MMBtu)
 
 
 
 
 
Residential
6,320

 
6,584

 
8,098

Commercial and industrial
8,165

 
9,116

 
10,626

Total retail
14,485

 
15,700

 
18,724

Transportation and other
4,847

 
4,756

 
4,729

Total deliveries
19,332

 
20,456

 
23,453

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
100,424

 
99,316

 
98,325

Commercial and industrial
13,015

 
12,902

 
12,773

Total retail
113,439

 
112,218

 
111,098

Transportation and other
30

 
25

 
23

Total customers
113,469

 
112,243

 
111,121

 
 
 
 
 
 
Natural gas revenues (Thousands of Dollars)
 
 
 
 
 
Residential
$
56,514

 
$
61,277

 
$
82,851

Commercial and industrial
46,879

 
55,677

 
82,181

Total retail
103,393

 
116,954

 
165,032

Transportation and other
2,764

 
3,193

 
4,597

Total natural gas revenues
$
106,157

 
$
120,147

 
$
169,629

 
 
 
 
 
 
MMBtu sales per retail customer
127.69

 
139.91

 
168.54

Revenue per retail customer
$
911

 
$
1,042

 
$
1,485

Residential revenue per MMBtu
8.94

 
9.31

 
10.23

Commercial and industrial revenue per MMBtu
5.74

 
6.11

 
7.73

Transportation and other revenue per MMBtu
0.57

 
0.67

 
0.97


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.


14


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. NSP-Wisconsin believes, based on prior state commission practice, it would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2016, NSP-Wisconsin had 558 full-time employees and two part-time employees, of which 399 were covered under collective-bargaining agreements. See Note 7 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

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

Oversight of Risk and Related Processes

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

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 NSP-Wisconsin’s strategy. The business planning process also 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.


15


At a threshold level, NSP-Wisconsin has developed a robust compliance program and promotes 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, NSP-Wisconsin manages and further mitigates 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 of Directors and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board of Directors in presentations and communications over the course of the year.

The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of NSP-Wisconsin. First, the Board of Directors regularly reviews management’s key risk assessment and analyzes areas of existing and future risks and opportunities. In addition, the Board of Directors 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 appropriate committee. 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 of Directors’ 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 of Directors for consideration where deemed appropriate to ensure broad Board of Directors’ understanding of the nature of the risk. Finally, the Board of Directors conducts an annual strategy session where NSP-Wisconsin’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, 2016, these sites included:

Sites of former MGPs operated by us, our predecessors or other entities; and
Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

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

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs, particulates, cooling water intakes, water discharges and ash management.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.


16


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

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

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

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

Climate change may impact a region’s economic health, which could impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as regulation of CO2 emissions under 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. We are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. 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 while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. 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.


17


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


18


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 NSP-Wisconsin could trigger settlement accounting and could require NSP-Wisconsin 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.

Changes in federal tax law may significantly impact our business.

There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping rates lower than without such provisions. Examples of these include the use of accelerated and bonus depreciation for most of our capital investments, PTCs for wind energy, investment tax credits for solar energy and research and development tax credits and deductions. Changes to current federal tax law have the ability to benefit or adversely affect our earnings and our customer costs. Significant changes in corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law. Changes to the value of various tax credits could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before realization of the changes.

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.


19


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

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

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

NSP-Minnesota’s two nuclear stations, 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, including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO2 emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if NSP-Wisconsin is not able to fully recover the costs and investments. These changes also 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. In addition, we are also subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources during the planning period could jeopardize long-term operations of our facilities or make them uneconomic to operate.


20


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 CO2 emissions profile. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes 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 and electric 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. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial financial losses. In addition, these natural gas and electric risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. We maintain insurance against some, but not all, of these risks and losses.

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

Additionally, for natural gas 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, 2016, Xcel Energy Inc. and its utility subsidiaries had approximately $14.2 billion of long-term debt and $0.6 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.


21


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, 2016, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $18.8 million and exposure of $0.1 million. Xcel Energy also had additional guarantees of $43.0 million at Dec. 31, 2016 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 2016, 2015 and 2014 we paid $53.1 million, $53.9 million and $43.8 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.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more 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.

In 2015, the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change 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 2o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5o Celsius. If implemented, 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 EPA has proposed the CPP, which would regulate GHGs from power plants by mandating state plans to achieve state-specific emission reduction goals. The legality of the CPP has been challenged in the courts, and the Supreme Court stayed the rule while those challenges proceed. If the rule is ultimately implemented, uncertainties remain regarding implementation plans, including available opportunities to reduce costs, availability of emission trading, 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.



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Some states have indicated a desire to continue to pursue climate policies even in the absence of federal mandates. All of the steps that NSP-Wisconsin has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put NSP-Wisconsin in a good position to meet federal standards under the CPP or the Paris Agreement, repeal of these policies would not impact those state-endorsed actions and plans.

Whether under state or federal programs, 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 PM, 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 $1.2 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. Under statute, the FERC can adjust penalties for inflation. 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. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties in the event of non-compliance. If a serious reliability or safety incident did occur, it could have a material effect on our operations or financial results.

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. We are also managing natural gas risk on our system by removing types of pipe (e.g. cast iron) with known problem tendencies and by testing transmission pipelines in high consequence areas. However, there is no guarantee our compliance programs will be sufficient to ensure against violations.

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.


23


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 our 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, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, 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.

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.


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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.

Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines for NSP-Wisconsin.

Item 1B — Unresolved Staff Comments

None.

Item 2Properties

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 2016
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
 
Oil
 
1974
 
122

 
Wheaton-Eau Claire, Wis., 5 Units
 
Natural Gas/Oil
 
1973
 
238

 
Hydro:
 
 
 
 
 
 
 
Various locations, 63 Units
 
Hydro
 
Various
 
135

 
 
 
 
 
Total
 
579

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


25


Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2016:
Conductor Miles
 
345 KV
1,153

161 KV
1,577

115 KV
1,817

Less than 115 KV
32,537


NSP-Wisconsin had 204 electric utility transmission and distribution substations at Dec. 31, 2016.

Natural gas utility mains at Dec. 31, 2016:
Miles
 
Distribution
2,395


Item 3 — Legal Proceedings

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

Additional Information

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

Item 4Mine Safety Disclosures

None.

PART II

Item 5Market 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 in excess of approximately $53.1 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 53.6 percent at Dec. 31, 2016 and $33.6 million in retained earnings was not restricted.

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


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The dividends declared during 2016 and 2015 were as follows:
(Thousands of Dollars)
 
2016
 
2015
First quarter
 
$
12,529

 
$
13,315

Second quarter
 
10,563

 
11,993

Third quarter
 
14,687

 
13,664

Fourth quarter
 
10,729

 
15,321


Item 6Selected 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 7Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed 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, 2016 (including 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 of cost of capital; and employee work force factors.

Results of Operations

NSP-Wisconsin’s net income was $69.1 million for 2016 compared with $74.6 million for 2015. The impact of the 2015 Monticello LCM/EPU project loss along with the positive impact of higher electric margins (primarily driven by an electric rate increase) was more than offset by higher O&M expenses and depreciation. See Note 10 to the consolidated financial statements for further discussion of the Monticello LCM/EPU project loss.


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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)
 
2016
 
2015
Electric revenues
 
$
850

 
$
835

Electric fuel and purchased power
 
(429
)
 
(430
)
Electric margin
 
$
421

 
$
405


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)
 
2016 vs. 2015
Retail rate increase
 
$
31

Interchange agreement billings with NSP-Minnesota
 
7

Fuel and purchased power cost recovery
 
(21
)
Other, net
 
(2
)
Total increase in electric revenues
 
$
15


Electric Margin
(Millions of Dollars)
 
2016 vs. 2015
Retail rate increase
 
$
31

Interchange agreement billings with NSP-Minnesota
 
(9
)
Fuel and purchased power cost recovery
 
(6
)
Total increase in electric margin
 
$
16


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)
 
2016
 
2015
Natural gas revenues
 
$
106

 
$
120

Cost of natural gas sold and transported
 
(54
)
 
(71
)
Natural gas margin
 
$
52

 
$
49


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)
 
2016 vs. 2015
Purchased natural gas adjustment clause recovery
 
$
(16
)
Estimated impact of weather
 
(1
)
Retail rate increase
 
3

Total decrease in natural gas revenues
 
$
(14
)


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Natural Gas Margin
(Millions of Dollars)
 
2016 vs. 2015
Retail rate increase
 
$
3

Estimated impact of weather
 
(1
)
Other, net
 
1

Total increase in natural gas margin
 
$
3


Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $15.5 million, or 8.6 percent, for 2016 compared with 2015.  The increase was primarily due to interchange agreement billings with NSP-Minnesota related to timing of transmission projects.

Depreciation and Amortization Depreciation and amortization increased $7.0 million, or 7.7 percent, for 2016 compared with 2015. The increase was primarily attributable to capital investments.

Interest Charges Interest charges increased $1.7 million, or 5.3 percent, for 2016 compared with 2015. The increase was primarily due to higher long-term debt levels.

Income Taxes Income tax expense decreased $1.3 million for 2016 compared with 2015.  The decrease in income tax expense was primarily due to lower pretax earnings in 2016 partially offset by decreased permanent plant-related adjustments (e.g., AFUDC-equity) in 2016. The ETR was 38.3 percent for 2016, compared with 37.2 percent for 2015. The higher ETR in 2016 is primarily due to the adjustments referenced above.

Item 7AQuantitative 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 non-performance risk.

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

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

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


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At Dec. 31, 2016 and 2015, a 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact annual pretax interest expense by approximately $0.6 million and $0.1 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, 2016 and 2015, 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.


30


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.

In 2016, NSP-Wisconsin implemented the general ledger modules, as well as initiated deployment of work management systems modules, of a new enterprise resource planning system. NSP-Wisconsin will continue to implement additional modules including the conversion of existing work management systems during 2017. NSP-Wisconsin does not believe this implementation has or will have an adverse effect on its internal control over financial reporting.

NSP-Wisconsin management assessed the effectiveness of NSP-Wisconsin’s internal control over financial reporting as of Dec. 31, 2016. 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, 2016, NSP-Wisconsin’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE
 
/s/ ROBERT C. FRENZEL
Ben Fowke
 
Robert C. Frenzel
Chairman and Chief Executive Officer
 
Executive Vice President, Chief Financial Officer
Feb. 24, 2017
 
Feb. 24, 2017


31


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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP
 
Minneapolis, Minnesota
 
February 24, 2017
 


32


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in thousands)
 
Year Ended Dec. 31
 
2016
 
2015
 
2014
Operating revenues
 
 
 
 
 
Electric
$
849,946

 
$
834,998

 
$
829,748

Natural gas
106,157

 
120,147

 
169,629

Other
1,130

 
1,396

 
1,085

Total operating revenues
957,233

 
956,541

 
1,000,462

 
 
 
 
 
 
Operating expenses
 
 
 
 
 
Electric fuel and purchased power, non-affiliates
15,574

 
10,795

 
19,595

Purchased power, affiliates
413,615

 
419,028

 
425,471

Cost of natural gas sold and transported
54,436

 
70,988

 
114,250

Operating and maintenance expenses
194,927

 
179,413

 
191,213

Conservation program expenses
12,645

 
11,695

 
11,537

Depreciation and amortization
98,294

 
91,245

 
79,654

Taxes (other than income taxes)
27,814

 
28,181

 
27,114

Loss on Monticello life cycle management/extended power uprate project

 
5,237

 

Total operating expenses
817,305

 
816,582

 
868,834

 
 
 
 
 
 
Operating income
139,928

 
139,959

 
131,628

 
 
 
 
 
 
Other income, net
461

 
883

 
270

Allowance for funds used during construction — equity
4,277

 
7,253

 
7,060

 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
Interest charges — includes other financing costs of
$1,854, $1,738, and $1,570, respectively
34,452

 
32,731

 
29,273

Allowance for funds used during construction — debt
(1,823
)
 
(3,510
)
 
(3,360
)
Total interest charges and financing costs
32,629

 
29,221

 
25,913

 
 
 
 
 
 
Income before income taxes
112,037

 
118,874

 
113,045

Income taxes
42,902

 
44,238

 
42,403

Net income
$
69,135

 
$
74,636

 
$
70,642


See Notes to Consolidated Financial Statements


33


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in thousands)
 
Year Ended Dec. 31
 
2016
 
2015
 
2014
Net income
$
69,135

 
$
74,636

 
$
70,642

 
 
 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
Reclassification of losses to net income, net of tax of $51 for the years ended Dec. 31, 2016, 2015, and 2014, respectively.
76

 
76

 
76

Other comprehensive income
76

 
76

 
76

Comprehensive income
$
69,211

 
$
74,712

 
$
70,718


See Notes to Consolidated Financial Statements


34


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)
 
Year Ended Dec. 31
 
2016
 
2015
 
2014
Operating activities
 
 
 
 
 
Net income
$
69,135

 
$
74,636

 
$
70,642

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
99,824

 
92,656

 
80,875

Deferred income taxes
37,368

 
45,833

 
45,396

Amortization of investment tax credits
(523
)
 
(528
)
 
(527
)
Allowance for equity funds used during construction
(4,277
)
 
(7,253
)
 
(7,060
)
Loss on Monticello life cycle management/extended power uprate project

 
5,237

 

Provision for bad debts
3,730

 
3,947

 
4,431

Net derivative losses
160

 
482

 
10

Other
(623
)
 

 

Changes in operating assets and liabilities:
 
 
 

 
 

Accounts receivable
(1,383
)
 
71

 
(5,558
)
Accrued unbilled revenues
(5,940
)
 
5,869

 
(1,933
)
Inventories
3,250

 
3,126

 
(3,210
)
Other current assets
(1,191
)
 
7,135

 
(3,501
)
Accounts payable
10,632

 
(7,626
)
 
2,936

Net regulatory assets and liabilities
(18,601
)
 
(27,114
)
 
(34,697
)
Other current liabilities
14,036

 
5,147

 
(911
)
Pension and other employee benefit obligations
(6,197
)
 
(3,177
)
 
(6,134
)
Change in other noncurrent assets
(718
)
 
209

 
(113
)
Change in other noncurrent liabilities
2,050

 
716

 
2,534

Net cash provided by operating activities
200,732

 
199,366

 
143,180

 
 
 
 
 
 
Investing activities
 
 
 
 
 
Utility capital/construction expenditures
(204,427
)
 
(251,797
)
 
(288,209
)
Allowance for equity funds used during construction
4,277

 
7,253

 
7,060

Other, net
1,198

 
(224
)
 
(166
)
Net cash used in investing activities
(198,952
)
 
(244,768
)
 
(281,315
)
 
 
 
 
 
 
Financing activities
 
 
 
 
 
Proceeds from (repayments of) short-term borrowings, net
50,000

 
(68,000
)
 
10,000

Proceeds from notes payable to affiliates

 

 
30

Proceeds from issuance of long-term debt

 
97,969

 
98,534

Repayments of long-term debt
(93
)
 
(87
)
 
(107
)
Capital contributions from parent
1,935

 
69,243

 
73,432

Dividends paid to parent
(53,100
)
 
(53,929
)
 
(43,818
)
Other, net
(55
)
 

 

Net cash (used in) provided by financing activities
(1,313
)
 
45,196

 
138,071

 
 
 
 
 
 
Net change in cash and cash equivalents
467

 
(206
)
 
(64
)
Cash and cash equivalents at beginning of period
1,079

 
1,285

 
1,349

Cash and cash equivalents at end of period
$
1,546

 
$
1,079

 
$
1,285

 
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(30,878
)
 
$
(27,491
)
 
$
(24,442
)
Cash received for income taxes, net
5,873

 
5,762

 
3,474

Supplemental disclosure of non-cash investing transactions:
 
 
 
 
 
Property, plant and equipment additions in accounts payable
$
16,172

 
$
16,729

 
$
35,267

See Notes to Consolidated Financial Statements

35


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in thousands, except share and per share data)
 
Dec. 31
 
2016
 
2015
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
1,546

 
$
1,079

Accounts receivable, net
54,031

 
56,378

Accrued unbilled revenues
53,638

 
47,698

Inventories
18,309

 
21,559

Regulatory assets
18,162

 
16,146

Prepaid taxes
25,915

 
25,976

Prepayments and other
3,785

 
2,387

Total current assets
175,386

 
171,223

 
 
 
 
Property, plant and equipment, net
1,947,637

 
1,828,079

 
 
 
 
Other assets
 
 
 
Regulatory assets
286,188

 
289,196

Other investments
2,844

 
4,042

Other
785

 
67

Total other assets
289,817

 
293,305

Total assets
$
2,412,840

 
$
2,292,607

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
1,123

 
$
1,131

Short-term debt
60,000

 
10,000

Notes payable to affiliates
500

 
500

Accounts payable
41,068

 
34,317

Accounts payable to affiliates
29,037

 
24,538

Dividends payable to parent
10,729

 
15,322

Regulatory liabilities
17,428

 
11,781

Environmental liabilities
41,438

 
17,155

Accrued interest
8,012

 
7,945

Other
26,484

 
15,146

Total current liabilities
235,819

 
137,835

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
430,593

 
391,063

Deferred investment tax credits
8,037

 
8,560

Regulatory liabilities
148,189

 
141,289

Environmental liabilities
23,003

 
77,441

Customer advances
19,425

 
18,480

Pension and employee benefit obligations
55,164

 
49,889

Other
18,814

 
16,347

Total deferred credits and other liabilities
703,225

 
703,069

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
661,946

 
661,318

Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares
outstanding at Dec. 31, 2016 and 2015, respectively
93,300

 
93,300

Additional paid in capital
395,315

 
394,553

Retained earnings
323,368

 
302,741

Accumulated other comprehensive loss
(133
)
 
(209
)
Total common stockholder’s equity
811,850

 
790,385

Total liabilities and equity
$
2,412,840

 
$
2,292,607


See Notes to Consolidated Financial Statements

36


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in thousands, except share data)
 
Common Stock
 
 
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Common
Stockholder’s
Equity
 
Shares
 
Par Value
 
Additional
Paid In
Capital
 
Retained
Earnings
 
 
Balance at Dec. 31, 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

Net income
 
 
 
 
 
 
69,135

 
 
 
69,135

Other comprehensive income
 
 
 
 
 
 
 
 
76

 
76

Common dividends declared to parent
 
 
 
 
 
 
(48,508
)
 
 
 
(48,508
)
Contribution of capital by parent
 
 
 
 
762

 
 
 
 
 
762

Balance at Dec. 31, 2016
933,000

 
$
93,300

 
$
395,315

 
$
323,368

 
$
(133
)
 
$
811,850


See Notes to Consolidated Financial Statements

37


NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands, except share and per share data)
 
Dec. 31
 
2016
 
2015
Long-Term Debt
 
 
 
First Mortgage Bonds, Series due:
 
 
 
Oct. 1, 2018, 5.25%
$
150,000

 
$
150,000

June 15, 2024, 3.3%
200,000

 
200,000

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%
456

 
490

Other
1,575

 
1,634

Unamortized discount
(2,865
)
 
(3,131
)
Unamortized debt expense
(4,697
)
 
(5,144
)
Total
663,069

 
662,449

Less current maturities
1,123

 
1,131

Total long-term debt
$
661,946

 
$
661,318

Common Stockholder’s Equity
 
 
 
Common stock  — 1,000,000 shares authorized of $100 par value;
 
 
 
933,000 shares outstanding at Dec. 31, 2016 and 2015, respectively
$
93,300

 
$
93,300

Additional paid in capital
395,315

 
394,553

Retained earnings
323,368

 
302,741

Accumulated other comprehensive loss
(133
)
 
(209
)
Total common stockholder’s equity
$
811,850

 
$
790,385


(a) 
Resource recovery financing

See Notes to Consolidated Financial Statements

38


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.


39


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

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.3, 3.4 and 3.3 percent for the years ended Dec. 31, 2016, 2015 and 2014, 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 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.


40


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 tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

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

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

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

See Note 6 for further discussion of income taxes.

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

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


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Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.

Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.  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.

Reclassifications Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 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 new framework for the recognition of revenue. NSP-Wisconsin expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers. NSP-Wisconsin has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be determined whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. NSP-Wisconsin currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

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 No. 2016-01 on its consolidated financial statements.


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Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. NSP-Wisconsin is currently evaluating the impact of adopting ASU No. 2016-02 on its consolidated financial statements.

Recently Adopted

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. NSP-Wisconsin implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. NSP-Wisconsin implemented the new guidance as required on Jan. 1, 2016, and as a result, $5.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

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 eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. NSP-Wisconsin implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 7 to the 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 eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the consolidated 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. NSP-Wisconsin early adopted the new guidance in the fourth quarter of 2016 and as a result $2.5 million of current deferred income taxes were retrospectively reclassified to offset long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. NSP-Wisconsin adopted the guidance in 2016, and the implementation did not have a material impact on its consolidated financial statements.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
Dec. 31, 2016