NORTHERN STATES POWER CO000007290912/312021FYFALSE010810779P3YP1YP2Y
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
Gains and Losses on Cash Flow Hedges
(Millions of Dollars)20212020
Accumulated other comprehensive loss at Jan. 1$— $— 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $—) (a)— — 
Net current period other comprehensive income (loss)— — 
Accumulated other comprehensive loss at Dec. 31$— $— 
(a)Included in interest charges.
Gains and Losses on Cash Flow Hedges
(Millions of Dollars)20212020
Accumulated other comprehensive loss at Jan. 1$— $— 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $—) (a)— — 
Net current period other comprehensive income (loss)— — 
Accumulated other comprehensive loss at Dec. 31$— $— 
(a)Included in interest charges.
—Included in interest charges.
Quarter Ended
(Millions of Dollars)March 31, 2021June 30, 2021Sept. 30, 2021Dec. 31, 2021
Operating revenues$257 $218 $251 $248 
Operating income41 23 46 31 
Net income34 12 40 21 
Quarter Ended
(Millions of Dollars)March 31, 2020June 30, 2020Sept. 30, 2020Dec. 31, 2020
Operating revenues$257 $218 $251 $248 
Operating income41 23 46 31 
Net income34 12 40 21 
Quarter Ended
(Millions of Dollars)March 31, 2021June 30, 2021Sept. 30, 2021Dec. 31, 2021
Operating revenues$257 $218 $251 $248 
Operating income41 23 46 31 
Net income34 12 40 21 
Quarter Ended
(Millions of Dollars)March 31, 2020June 30, 2020Sept. 30, 2020Dec. 31, 2020
Operating revenues$257 $218 $251 $248 
Operating income41 23 46 31 
Net income34 12 40 21 

Washington, D.C. 20549
(Mark One)
For the fiscal year ended December 31, 2021 or
For the transition period from _____ to _____
(Commission File Number)
Northern States Power Company
(Exact name of registrant as specified in its charter)
(State or Jurisdiction or Incorporation or Organization)(IRS Employer Identification No.)
1414 West Hamilton Avenue
Eau Claire
(Address of Principal Executive Offices)(Zip Code)
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
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 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 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. Yes No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of 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 such files). Yes No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  Large accelerated filer  Accelerated filer  Non-accelerated filer Smaller reporting company Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes  No
As of Feb. 23, 2022, 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.
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 2022 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 5, 2022. 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).


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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.

Table of Contents
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e primee prime inc.
NSP-MinnesotaNorthern States Power Company, a Minnesota corporation
NSP SystemThe electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-WisconsinNorthern States Power Company, a Wisconsin corporation
PSCoPublic Service Company of Colorado
SPSSouthwestern Public Service Company
Utility subsidiariesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel EnergyXcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
DOTDepartment of Transportation
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
IRSInternal Revenue Service
MPSCMichigan Public Service Commission
NERCNorth American Electric Reliability Corporation
NRCNuclear Regulatory Commission
PHMSAPipeline and Hazardous Materials Safety Administration
PSCWPublic Service Commission of Wisconsin
SECSecurities and Exchange Commission
AFUDCAllowance for funds used during construction
AROAsset retirement obligation
ASCFASB Accounting Standards Codification
C&ICommercial and Industrial
CapX2020Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CEOChief executive officer
CFOChief financial officer
COVID-19Novel coronavirus
CWAClean Water Act
CWIPConstruction work in progress
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DSMDemand side management
EMANIEuropean Mutual Association for Nuclear Insurance
ETREffective tax rate
FASBFinancial Accounting Standards Board
GAAPGenerally accepted accounting principles
GHGGreenhouse gas
INPOInstitute of Nuclear Power Operations
ISOIndependent System Operators
ITCInvestment tax credit
MGPManufactured gas plant
MISOMidcontinent Independent System Operator, Inc.
NAVNet asset value
NEILNuclear Electric Insurance Ltd.
NOLNet operating loss
NOPRNotice of proposed rulemaking
O&MOperating and maintenance
Per- and PolyFluoroAlkyl Substances
PPAPurchased power agreement
RECRenewable energy credit
ROEReturn on equity
RTORegional Transmission Organization
SERPSupplemental executive retirement plan
TCJA2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
TOTransmission owner
VIEVariable interest entity
BcfBillion cubic feet
KWhKilowatt hours
MMBtuMillion British thermal units
MWhMegawatt hours
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, including those relating to future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” 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, 2021 (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 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of NSP-Wisconsin to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; and regulatory changes and/or limitations related to the use of natural gas as an energy source.
Where to Find More Information
NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc. and Xcel Energy’s website address is Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.
Electric customers0.3 million
NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin conducts business in Wisconsin and Michigan and generates, transmits, distributes and sells electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.
Natural gas customers0.1 million
Total assets$3.1 billion
Rate Base (estimated)$2.0 billion
ROE (net income / average stockholder's equity)9.92%
Electric generating capacity548 MW
Gas storage capacity3.8 Bcf
Electric transmission lines (conductor miles)12,409 miles
Electric distribution lines (conductor miles)27,701 miles
Natural gas transmission lines3 miles
Natural gas distribution lines2,526 miles
Electric Operations
Electric operations consist of energy supply, generation, transmission and distribution activities. NSP-Wisconsin had electric sales volume of 6,786 (millions of KWh), 0.3 million customers and electric revenues of $922 (millions of dollars) for 2021.

Retail Sales/Revenue Statistics (a)
KWh sales per retail customer25,490 24,999 
Revenue per retail customer$2,693 $2,580 
Residential revenue per KWh13.79 ¢13.30 ¢
Large C&I revenue per KWh7.62 ¢7.53 ¢
Small C&I revenue per KWh10.31 ¢9.99 ¢
Total retail revenue per KWh10.57 ¢10.32 ¢
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 2021
Electric Energy Sources
Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2021:
*Distributed generation from the Solar*Rewards® program is not included (approximately 34 million KWh for 2021).
Carbon–Free — NSP System
The NSP System’s carbon–free energy portfolio includes nuclear, wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. Carbon–free percentages will vary year over year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Carbon–free energy as a percentage of total energy for 2021:
* Includes biomass and hydroelectric
Owned — Owned and operated wind farms with corresponding capacity:
Wind Farms
Capacity (a)
Wind Farms
Capacity (b)
142,031 MW111,540 MW
(a)    Summer 2021 net dependable capacity.
(b)    Summer 2020 net dependable capacity.
PPAs — Number of PPAs with capacity range:
1281 MW — 206 MW1291 MW — 206 MW
Capacity — Wind capacity:
3,997 MW3,348 MW
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
$25 $23 
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
$37 $38 
Wind Development
The NSP System placed approximately 500 MW of owned wind and approximately 255 MW of PPAs into service during 2021:
ProjectCapacity (MW)
Blazing Star 2
200 (a)(b)
200 (a)(b)
91 (a)(b)
~255 (c)
(a)Summer 2021 net dependable capacity.
(b)Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(c)Based on contracted capacity.

The NSP System currently has approximately 1,050 MW of owned wind under development or being repowered. In addition, the NSP System expects to add approximately 200 MW of planned PPAs.
ProjectCapacity (MW)Estimated Completion
Northern Wind1002022
Dakota Range300
     2022 (a)
Grand Meadow1002023
Border Winds1502025
Pleasant Valley2002025
Various PPAs~2002022
(a) Placed in service in January 2022.
Solar energy PPAs:
TypeCapacity (MW)
Distributed Generation994
Total 1,262
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
$90 $90 
Solar Development
In June 2021, the PSCW approved NSP-Wisconsin’s request to purchase the 74 MW Western Mustang build-own-transfer solar facility for approximately $100 million. Also, as part of the Minnesota Recovery and Relief Recovery docket, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an incremental investment of approximately $575 million. An MPUC decision is expected by the third quarter of 2022.
The NSP System has two nuclear plants (owned by NSP-Minnesota) with approximately 1,700 MW of total 2021 net summer dependable capacity. NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. NSP-Minnesota uses varying contract lengths as well as multiple producers for uranium concentrates, conversion services and enrichment services to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Nuclear Fuel Cost
Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements:
2021$0.77 46 %
20200.80 51 
Other NSP System
The NSP System’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.

Fossil Fuel — NSP System
The NSP System’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
The NSP System owns and operates coal units with approximately 2,400 MW of total 2021 net summer dependable capacity.
Approved early coal plant retirements:
YearPlant UnitCapacity (MW)
2023Sherco 2682
2026Sherco 1680
2028A.S King511
2030Sherco 3
517 (a)
(a)    Based on the NSP System’s ownership percentage.
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:
Coal (a)
2021$1.60 39 %
20201.97 31 
(a)    Includes refuse-derived fuel and wood for the NSP System.
Natural Gas
The NSP System has eight natural gas plants with approximately 2,800 MW of total 2021 net summer dependable capacity.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements:
Natural Gas
2021 (a)
$4.98 15 %
20202.67 17 
(a)Reflective of Winter Storm Uri.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
System Peak Demand (MW)
8,837 June 98,571 July 8


Transmission lines deliver electricity over long distances from power sources to transmission substations closer to customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. NSP-Wisconsin owns more than 12,000 conductor miles of transmission lines across its service territory.
See Item 2 — Properties for further information.

Distribution lines allow electricity to travel at lower voltages from substations directly to customers. NSP-Wisconsin has a vast distribution network, owning and operating approximately 28,000 conductor miles of distribution lines across our service territory. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.
See Item 2 — Properties for further information.
Natural Gas Operations
Natural gas operations consist of purchase, transportation, and distribution of natural gas to end-use residential, C&I and transport customers. NSP-Wisconsin had natural gas deliveries of 21,111 (thousands of MMBtu), 0.1 million customers and natural gas revenues of $182 (millions of dollars) for 2021.
Sales/Revenue Statistics (a)
MMBtu sales per retail customer133 140 
Revenue per retail customer$1,449 $976 
Residential revenue per MMBtu12.55 8.91 
C&I revenue per MMBtu9.53 5.46 
Transportation and other revenue per MMBtu1.72 0.69 
(a)See Note 6 to the consolidated financial statements for further information.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).
Maximum daily output (firm and interruptible) and occurrence date:
2021 (a)
167,656 Feb. 11150,320 Dec. 24
(a)Reflective of Winter Storm Uri.
Natural Gas Supply and Costs
NSP-Wisconsin seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility and decrease interruption and financial risks and economical rates. In addition, NSP-Wisconsin conducts natural gas price hedging activities approved by its states’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
2021 (a)
$7.11 $3.08 
(a)Reflective of Winter Storm Uri.
NSP-Wisconsin has natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
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.
NSP-Wisconsin is subject to public policies that promote competition and development of energy markets. NSP-Wisconsin’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.

Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Wisconsin has incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to NSP-Wisconsin’s electric service business with these incentives and federal tax subsidies.
FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state laws that allow the incumbent a Right of First Refusal to own these transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
NSP-Wisconsin has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization. No municipalization activities are occurring presently.
While facing these challenges, NSP-Wisconsin believes its rates and services are competitive with alternatives currently available.
Governmental Regulations
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid and hazardous wastes or substances. Certain NSP-Wisconsin activities require registrations, permits, licenses, inspections and approvals from these agencies. NSP-Wisconsin has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine what additional facilities or modifications of existing or planned facilities will be required as a result of changes to regulations, interpretations or enforcement policies or what effect future laws or regulations may have. We may be required to incur expenditures in the future for remediation of MGP and other sites.
NSP-Wisconsin must comply with emission levels that may require the purchase of emission allowances.
There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. NSP-Wisconsin has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Future environmental regulations may result in substantial costs.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans by 2022 for GHG reductions from coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision would allow the EPA to proceed with alternate regulation of coal-fired power plants. However, the Court of Appeals decision is now before the U.S. Supreme Court, where the Court is expected to rule on the nature and extent of the EPA’s GHG regulatory authority. If any new rules require additional investment, NSP-Wisconsin believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
NSP-Wisconsin seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
Emerging Environmental Regulation
New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the environment. These chemicals have received heightened attention from environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal, state, and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. NSP-Wisconsin will continue to monitor these regulatory developments and their potential impact on its operations.
Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.
As of Dec. 31, 2021, NSP-Wisconsin had 518 full-time employees and one part-time employee, of which 382 were covered under collective-bargaining agreements.

Xcel Energy, which includes NSP-Wisconsin, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that we file with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
NSP-Wisconsin’s Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, NSP-Wisconsin maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. NSP-Wisconsin further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental and security risks.
The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of NSP-Wisconsin. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks.
Operational Risks
Our natural gas and electric generation/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 inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages.
These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to employees, third-party contractors, customers or the public. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining NSP-Wisconsin's facilities include, but are not limited to:
Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
Failures in the availability, acquisition or transportation of fuel or other necessary supplies.
The impact of unusual or adverse weather conditions and natural disasters, including, but not limited to, tornadoes, icing events, floods and droughts.
Performance below expected or contracted levels of output or efficiency (e.g., performance guarantees).
Availability of replacement equipment.
Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
Inability to identify, manage properly or mitigate equipment defects.
Use of new or unproven technology.
Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with the PHMSA regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.

Table of Contents
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Higher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact project plans. Such impacts could include timing of projects, including potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel 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 could impact our cash flows and liquidity.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. 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. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.
Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing, NSP-Wisconsin is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, NSP-Wisconsin cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct. If such programs and procedures are not effective, NSP-Wisconsin’s results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
In 2021, the competition for talent has become increasingly intense as a result of the ongoing “great resignation”, and we may experience increased employee turnover due to this tightening labor market. In addition, specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

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Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.
We are exposed to risk of employee or third-party contractor fraud or other misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate
in annual training. Additionally, suppliers are subject to comply with our supplier Code of Conduct. NSP-Wisconsin does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.
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 has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:
Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.
Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.
Technological and financial uncertainties related to the costs of decommissioning nuclear plants 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, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.
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. 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.
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 of Directors 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 2021, 2020 and 2019 we paid $103 million, $70 million and $84 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 Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to future test years. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.

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Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings.
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 credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement 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 market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
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 economy and unemployment rates.
Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
We may have direct credit exposure as part of our local gas distribution company supply activity to 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, (e.g., MISO), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
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 either Standard & Poor’s Global Ratings or Moody’s Investor Services 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, 2021, Xcel Energy Inc. and its utility subsidiaries had approximately $21.8 billion of long-term debt and $1.6 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.
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, 2021, Xcel Energy had guarantees outstanding with a $1 million maximum stated amount and immaterial exposure. Xcel Energy also had additional guarantees of $59 million at Dec. 31, 2021 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.

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Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
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 have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high numbers of retirements or employees leaving NSP-Wisconsin would trigger settlement accounting and could require NSP-Wisconsin to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid, to the extent they are not subject to a regulatory deferral. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
Federal tax law may significantly impact our business.
NSP-Wisconsin collects estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, NSP-Wisconsin faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 continues to impact countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic; the duration and magnitude of business restrictions (domestically and globally); the potential shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; re-shutdowns, if any, and the level and pace of economic recovery.
Although the financial impact of the pandemic on our financial results has largely been mitigated, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or 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, results of operations or cash flows. 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. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance 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, brand and reputation. Because our facilities 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.
We also face the risks of possible loss of business due to significant events such as severe storms, severe temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
A major disruption could result in a significant decrease in revenues and additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
NSP-Wisconsin participates in GridEx, which is the largest grid security exercise in North America. These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

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A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control 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 information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. During the normal course of business, we have experienced and expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operation.
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 causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose 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.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
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. 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.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, 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, 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. In April 2021, ahead of the United Nations Climate Change Conference in Glasgow, the Biden Administration committed the U.S. to a Nationally Determined Contribution of 50-52% net GHG emissions reduction economy-wide from 2005 levels. This commitment and other agreements made in Glasgow could result in future additional GHG reductions in the United States. In addition, the Biden Administration has announced plans to implement new climate change programs, including potential regulation of GHG emissions targeting the utility industry.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy 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.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
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 condition or cash flows.

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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 impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.
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 operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. 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 generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, 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.
We have committed to a number of long-term climate change goals, which in part are dependent on future technologies not currently in existence. Given the long-term nature of these goals, there is an inherent uncertainty due to internal and external factors regarding our ability to achieve our stated climate change goals. To the extent climate change goals are not met, this could negatively impact our reputation and potentially result in financial risk.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities.
While we carry liability insurance, given an extreme event, if NSP-Wisconsin was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.

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

Station, Location and Unit at Dec. 31, 2021
MW (a)
Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 
French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 
Combustion Turbine:
French Island-La Crosse, WI, 2 UnitsOil1974122 
Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 
Various locations, 63 UnitsHydroVarious135 
(a)Summer 2021 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2021:
Conductor Miles
345 KV2,943 
161 KV1,778 
115 KV1,818 
Less than 115 KV5,870 
Total Transmission12,409 
Less than 115 KV27,701 
NSP-Wisconsin had 204 electric utility transmission and distribution substations at Dec. 31, 2021.
Natural gas utility mains at Dec. 31, 2021:
NSP-Wisconsin is involved in various litigation matters 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 losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on NSP-Wisconsin’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.
NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
The dividends declared during 2021 and 2020 were as follows:
(Millions of Dollars)20212020
First quarter$19 $17 
Second quarter15 20 
Third quarter50 18 
Fourth quarter26 19 
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 and the results of operations for the current year as set forth in General Instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
NSP-Wisconsin’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items
We use these non-GAAP financial measures to evaluate and provide details of NSP-Minnesota’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of NSP-Wisconsin. For the years ended Dec. 31, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.

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Results of Operations
2021 Comparison with 2020
NSP-Wisconsin’s net income was $108 million for 2021 compared with $107 million for 2020. The increase largely reflects regulatory outcomes primarily offset by income tax expenses.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for production tax credits generated, which reduce electric revenue and income taxes.
Electric Revenues, Fuel and Purchased Power and Electric Margin
(Millions of Dollars)20212020
Electric revenues$922 $855 
Electric fuel and purchased power(428)(392)
Electric margin$494 $463 
Changes in Electric Margin
(Millions of Dollars)2021 vs. 2020
Regulatory rate outcomes $24 
Sales and demand
Estimated impact of weather
Other (net)(3)
Total increase in electric margin$31 
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
(Millions of Dollars)20212020
Natural gas revenues$182 $119 
Cost of natural gas sold and transported(117)(53)
Natural gas margin$65 $66 
Decrease in natural gas margin is primarily due to a decline in retail sales growth.
Non-Fuel Operating Expenses and Other Items
Depreciation and Amortization — Depreciation and amortization decreased $9 million for 2021 compared with 2020. The decrease is due to lower amortization of environmental regulatory assets, partially offset by normal system expansion and deferred tax liability amortization.
Income Taxes Income tax expense increased $37 million for 2021. The increase was primarily driven by a decrease in plant regulatory differences, lower non-plant accumulated deferred income tax amortization and higher pretax earnings in 2021.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, NSP-Wisconsin incurred net natural gas, fuel and purchased energy costs of approximately $45 million (which were largely deferred as regulatory assets).
Regulatory Overview NSP-Wisconsin has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, NSP-Wisconsin deferred February 2021 cost increases over a period of up to 10 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers.
JurisdictionRegulatory Status
WisconsinIn March, the PSCW approved NSP-Wisconsin’s proposal to recover $45 million of Winter Storm Uri natural gas costs over nine months through December 2021 with no financing charge.
MichiganIn May, the MPSC approved recovery of $2 million in natural gas costs over 10 months with no financing charge.
Public Utility Regulation
The FERC and various state and local regulatory commissions regulate NSP-Wisconsin. The electric and natural gas rates charged to customers of NSP-Wisconsin are approved by the FERC or the regulatory commissions in the states in which it operates.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. NSP-Wisconsin requests changes in utility rates through commission filings.
Changes in operating costs can affect NSP-Wisconsin’s financial results, depending on the timing of rate case filings and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact NSP-Wisconsin’s results of operations.
See Rate Matters within Note 10 to the consolidated financial statements for further information.

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
Additional Information
Retail rates, services and other aspects of electric and natural gas operations.
Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.
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.
Pipeline safety compliance.
Retail rates, services and other aspects of electric and natural gas operations.
Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.
Pipeline safety compliance.
Wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, 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 is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.
Pipeline safety compliance.
Recovery Mechanisms
Additional Information
Annual Fuel Cost Plan
NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% 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. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.
Power Supply Cost Recovery Factors
NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.
Wisconsin Energy Efficiency Program
The primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from customers.
Purchased Gas Adjustment
A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.
Natural Gas Cost-Recovery Factor (MI)
NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.

Pending and Recently Concluded Regulatory Proceedings
Wisconsin Electric and Natural Gas Settlement — In December 2021, the PSCW approved a rate case settlement agreement and 2022 fuel cost plan without modification. New rates and tariffs were effective Jan. 1, 2022. Key elements of the settlement:
An increase in electric rates of $35 million (4.9%) for 2022 and an incremental $18 million increase (2.5%) for 2023.
An increase in natural gas rates of $10 million (8.4%) for 2022 and an incremental $3 million (2.3%) for 2023.
ROE of 9.80% for 2022 and 10.00% for 2023.
Equity ratio of 52.5% for both 2022 and 2023.
Returning $9 million in various net regulatory liabilities to offset customer impacts in 2023.
Deferring certain pension and other post-employment benefit expense in 2021 through 2023.
Incorporating an earnings sharing mechanism for 2022 and 2023.
Michigan Electric Rate Case — In January 2022, NSP-Wisconsin reached an electric rate case settlement in principle with the MPSC staff and others. The settlement grants NSP-Wisconsin an electric revenue increase of $1.6 million in 2022, based on a ROE of 9.7% and an equity ratio of 52.5%. The MPSC is expected to rule on the settlement in the first quarter of 2022.
FERC NOPR on ROE Incentive Adders — In April 2021, the FERC issued a NOPR proposing to limit collection of ROE incentive adders for RTO membership to the first three years after an entity begins participation in an RTO. If adopted as a final rule, NSP-Minnesota would prospectively discontinue charging their current 50 basis point ROE incentive adders. Amounts related to a discontinuance of the adder would ultimately be offset by an increase in retail rates, subject to future rate cases.
Purchased Power and Transmission Services
The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or 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.
Wholesale and Commodity Marketing Operations
NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates.

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 8 to the consolidated financial statements for further information.
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, 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 certain credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund and NSP-Wisconsin’s ability to earn a return on short-term investments.
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 long- and short-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 per commission approved hedge plans.

Interest Rate Risk — NSP-Wisconsin is subject to interest rate risk. 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.
A 100 basis point change in the benchmark rate on NSP-Wisconsin’s variable rate debt would impact pretax interest expense annually by $1 million and an immaterial amount for the year ended Dec. 31, 2021 and 2020, respectively.
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 monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2021 and 2020, a 10% increase or decrease in commodity prices would have no impact on credit exposure.
NSP-Wisconsin conducts credit reviews for all counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. 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.
See Note 8 to the consolidated financial statements for further information.
See Item 15-1 for an index of financial statements included herein.
See Note 13 to the consolidated financial statements for further information.


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Management Report on Internal Control Over Financial Reporting
The management of NSP-Wisconsin is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Wisconsin’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and NSP-Wisconsin’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
NSP-Wisconsin management assessed the effectiveness of NSP-Wisconsin’s internal control over financial reporting as of Dec. 31, 2021. 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, 2021, NSP-Wisconsin’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
Robert C. FrenzelBrian J. Van Abel
Chairman, Chief Executive Officer and DirectorExecutive Vice President, Chief Financial Officer and Director
Feb. 23, 2022Feb. 23, 2022


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To the stockholder and the Board of Directors of Northern States Power Company, a Wisconsin corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Northern States Power Company, a Wisconsin corporation and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting 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.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 10 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Wisconsin and Michigan. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
Minneapolis, Minnesota
February 23, 2022
We have served as the Company’s auditor since 2002.


(amounts in millions)
Year Ended Dec. 31
Operating revenues
Electric, non-affiliates$733 $687 $668 
Electric, affiliates189 168 177 
Natural gas182 119 136 
Other— — 
Total operating revenues1,105 974 981 
Operating expenses
Electric fuel and purchased power, non-affiliates20 13 11 
Purchased power, affiliates408 379 394 
Cost of natural gas sold and transported117 53 65 
Operating and maintenance expenses198 191 201 
Conservation program expenses13 13 12 
Depreciation and amortization147 156 138 
Taxes (other than income taxes)28 28 29 
Total operating expenses931 833 850 
Operating income174 141 131 
Other expense, net(1)(8)(1)
Allowance for funds used during construction — equity
Interest charges and financing costs
Interest charges — includes other financing costs of $1, $1 and $1, respectively
42 40 39 
Allowance for funds used during construction — debt(2)(2)(1)
Total interest charges and financing costs40 38 38 
Income before income taxes138 100 95 
Income tax expense (benefit)30 (7)16 
Net income$108 $107 $79 

See Notes to Consolidated Financial Statements


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(amounts in millions)
Year Ended Dec. 31
Operating activities
Net income$108 $107 $79 
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization148 158 139 
Deferred income taxes(36)
Allowance for equity funds used during construction(5)(5)(3)
Provision for bad debts
Changes in operating assets and liabilities:
Accounts receivable(5)(12)(10)
Accrued unbilled revenues(16)— 
Other current assets(4)(3)13 
Accounts payable(3)(10)
Net regulatory assets and liabilities(41)— 15 
Other current liabilities11 
Pension and other employee benefit obligations(9)(7)(7)
Other, net(1)(3)— 
Net cash provided by operating activities186 202 234 
Investing activities
Capital/construction expenditures(264)(238)(212)
Investments in utility money pool arrangement(71)— — 
Repayments from money pool arrangement71 — — 
Net cash used in investing activities(264)(238)(212)
Financing activities
Proceeds from (repayments of) short-term borrowings, net64 (46)13 
Proceeds from issuance of long-term debt99 97 — 
Repayments of long-term debt(19)— — 
Borrowings under money pool arrangement358 — — 
Repayments under money pool arrangement(358)— — 
Capital contributions from parent46 56 48 
Dividends paid to parent(103)(70)(84)
Net cash provided by (used in) financing activities87 37 (23)
Net change in cash, cash equivalents and restricted cash(1)
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period$11 $$
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)$(38)$(36)$(36)
Cash paid for income taxes, net(22)(26)— 
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions$43 $21 $29 
Inventory transfers to property, plant and equipment
Allowance for equity funds used during construction

See Notes to Consolidated Financial Statements

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(amounts in millions, except share and per share data)
Dec. 31
Current assets
Cash and cash equivalents$11 $
Accounts receivable, net71 70 
Accrued unbilled revenues69 53 
Other receivables
Inventories27 15 
Regulatory assets21 19 
Prepaid taxes25 24 
Prepayments and other
Total current assets234 191 
Property, plant and equipment, net2,660 2,484 
Other assets
Regulatory assets225 215 
Other investments
Total other assets229 219 
Total assets$3,123 $2,894 
Liabilities and Equity
Current liabilities
Current portion of long-term debt$— $19 
Short-term debt83 19 
Accounts payable69 41 
Accounts payable to affiliates23 15 
Dividends payable to parent26 19 
Regulatory liabilities31 
Taxes accrued10 12 
Environmental liabilities
Accrued interest10 10 
Other17 15 
Total current liabilities246 185 
Deferred credits and other liabilities
Deferred income taxes325 307 
Deferred investment tax credits
Regulatory liabilities372 350 
Environmental liabilities14 16 
Customer advances23 20 
Pension and employee benefit obligations16 28 
Other32 27 
Total deferred credits and other liabilities787 754 
Commitments and contingencies
Long-term debt987 887 
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares
     outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively
93 93 
Additional paid in capital642 605 
Retained earnings368 370 
Total common stockholder's equity1,103 1,068 
Total liabilities and equity$3,123 $2,894 

See Notes to Consolidated Financial Statements

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(amounts in millions, except share data)
Common StockTotal
SharesPar ValueAdditional
Paid In
Balance at Dec. 31, 2018933,000 $93 $510 $339 $942 
Net income79 79 
Common dividends declared to parent(81)(81)
Contribution of capital by parent27 27 
Balance at Dec. 31, 2019933,000 $93 $537 $337 $967 
Net income107 107 
Common dividends declared to parent(74)(74)
Contribution of capital by parent68 68 
Balance at Dec. 31, 2020933,000 $93 $605 $370 $1,068 
Net income108 108 
Common dividends declared to parent(110)(110)
Contribution of capital by parent37 37 
Balance at Dec. 31, 2021933,000 $93 $642 $368 $1,103 

See Notes to Consolidated Financial Statements

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Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
General — 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 include its wholly-owned subsidiaries and VIEs 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.
NSP-Wisconsin’s consolidated financial statements 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. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
NSP-Wisconsin has evaluated events occurring after Dec. 31, 2021 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — NSP-Wisconsin uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for items such 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. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — NSP-Wisconsin accounts for 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 other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates or because the amounts were collected in rates prior to the costs being incurred.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If 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 results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires 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 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 the period that includes the enactment date.
The effects of NSP-Wisconsin’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which would be refundable to utility customers over the remaining life of the related assets. NSP-Wisconsin anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.
Reversal of certain temporary differences are accounted for as current income tax expense 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. 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 regulatory assets and liabilities related to income taxes. 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.
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 expense.
NSP-Wisconsin reports interest and penalties related to income taxes within other (expense) income or interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.

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Property, Plant and Equipment and Depreciation in Regulated Operations — 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 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 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 using the straight-line method over the plant’s commission-approved 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. Plant removal costs are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.6% in 2021, 3.6% in 2020 and 3.6% in 2019.
See Note 3 for further information.
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.
See Note 10 for further information.
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 requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 9 for further information.
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. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Wisconsin recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically 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 does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Wisconsin presents its revenues net of any excise or sales taxes or fees.
NSP-Wisconsin has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. 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, 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. 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-recovery or over-recovery of fuel costs in excess of a 2% annual tolerance band, for future rate recovery or refund, subject to PSCW approval.
Cash and Cash Equivalents — NSP-Wisconsin considers investments in instruments 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.
As of both Dec. 31, 2021 and 2020, the allowance for bad debts was $8 million.

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Inventory — Inventory is recorded at average cost and consisted of the following:
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Materials and supplies$$
Natural gas10 
Total inventories$27 $15 
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 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, NSP-Wisconsin may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.
For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.
See Notes 8 and 9 for further information.
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. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. 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. 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.
Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.
See Note 8 for further information.
Other Utility Items
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility rates.
Alternative Revenue — Certain rate rider mechanisms qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate or from other instances where the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
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% 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.
Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
RECs Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense.
Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs are recorded in electric fuel and purchased power expense.
2. Accounting Pronouncements
Recently Adopted
Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.
NSP-Wisconsin implemented the guidance using a modified-retrospective approach, recognizing an immaterial cumulative effect charge (after tax) to retained earnings on Jan 1. 2020. The Jan. 1, 2020 adoption of ASC Topic 326 did not have a significant impact on NSP-Wisconsin’s consolidated financial statements.


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3. Property, Plant, and Equipment
Major classes of property, plant and equipment
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Property, plant and equipment, net
Electric plant$3,348 $3,197 
Natural gas plant423 391 
Common and other property233 221 
CWIP134 71 
Total property, plant and equipment4,138 3,880 
Less accumulated depreciation(1,478)(1,396)
Property, plant and equipment, net$2,660 $2,484 

Joint Ownership of Transmission Facilities
Jointly owned assets as of Dec. 31, 2021:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
Electric transmission:
La Crosse, WI to Madison, WI$177 $15 37 %
CapX2020169 28 80 
Total (a)
$346 $43 
(a)Projects additionally include $2 million in CWIP.
NSP-Wisconsin’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2021Dec. 31, 2020
Regulatory AssetsCurrentNoncurrentCurrentNoncurrent
Environmental remediation costs1, 10Various$13 $79 $13 $94 
Pension and retiree medical obligations9Various55 67 
Deferred natural gas and electric energy/fuel costs7
One to two years
29 — — 
State commission adjustmentsPlant lives21 20 
Recoverable deferred taxes on AFUDCPlant lives— 19 — 18 
Net AROs (a)
1, 10Various— 10 — 
Losses on reacquired debtTerm of related debt— — 
Total regulatory assets$21 $225 $19 $215 
(a)Includes amounts recorded for future recovery of AROs.
Components of regulatory liabilities:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2021Dec. 31, 2020
Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Plant removal costs1, 10Various$— $201 $— $184 
Deferred income tax adjustments and TCJA refunds (a)
7Various— 152 — 161 
United States Department of Energy SettlementVarious— 14 12 — 
Deferred natural gas and electric energy/fuel costsLess than one year— 17 
Total regulatory liabilities$$372 $31 $350 
(a)    Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.
At Dec. 31, 2021 and 2020, NSP-Wisconsin had no regulatory assets of past expenditures that were not eligible to earn a return.


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5. Borrowings and Other Financing Instruments
Short Term Borrowings
NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. NSP-Wisconsin began participation in the money pool in 2021 following approval by the PSCW in October 2020.
Money pool borrowings:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2021Year Ended
Borrowing limit$150 $150 
Amount outstanding at period end— — 
Average amount outstanding31 16 
Maximum amount outstanding78 78 
Weighted average interest rate, computed on a daily basis0.05 %0.05 %
Weighted average interest rate at period endN/AN/A
Commercial Paper — Commercial paper outstanding:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2021Year Ended Dec. 31
Borrowing limit$150 $150 $150 $150 
Amount outstanding at period end83 83 19 65 
Average amount outstanding30 51 
Maximum amount outstanding83 83 95 93 
Weighted average interest rate, computed on a daily basis0.21 0.18 1.59 2.38 
Weighted average interest rate at end of period0.21 0.21 0.17 1.97 
Letters of Credit — NSP-Wisconsin may use letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2021 and 2020, there were no letters of credit outstanding.
Credit Facility — In order to use commercial paper programs to fulfill short-term funding needs, NSP-Wisconsin must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Features of the credit facility:
Debt-to-Total Capitalization Ratio (a)
Amount Facility May Be Increased (millions of dollars)
Additional Periods for Which a One-Year Extension May Be Requested (b)
49 %46 %N/A
(a)    The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b)    All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that NSP-Wisconsin would be in default on borrowings under the facility if NSP-Wisconsin or any of its subsidiaries, whose total assets exceed 15% of NSP-Wisconsin’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.
If NSP-Wisconsin does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2021, NSP-Wisconsin was in compliance with all financial covenants.
NSP-Wisconsin had the following committed credit facility available as of Dec. 31, 2021 (in millions of dollars):
Credit Facility (a)
Drawn (b)
$150 $83 $67 
(a)This credit facility matures in June 2024.
(b)Includes outstanding commercial paper.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the facility outstanding at Dec. 31, 2021 and 2020, respectively.
Other Short-Term Borrowings — Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, had an immaterial note payable to Xcel Energy Inc. at Dec. 31, 2021 and 2020, respectively.
Long-Term Borrowings and Other Financing Instruments
Generally, all property of NSP-Wisconsin is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of new issuance.
Long-term debt obligations for NSP-Wisconsin as of Dec. 31 (in millions of dollars):
Financing InstrumentInterest RateMaturity Date20212020
City of La Crosse resource recovery bond6.00 %Nov. 1, 2021$— $19 
First mortgage bonds3.30 June 15, 2024100 100 
First mortgage bonds3.30 June 15, 2024100 100 
First mortgage bonds6.375 Sept. 1, 2038200 200 
First mortgage bonds3.70 Oct. 1, 2042100 100 
First mortgage bonds3.75 Dec. 1, 2047100 100 
First mortgage bonds 4.20 Sept. 1, 2048200 200 
First mortgage bonds (b)
3.05 May 1, 2051100 100 
First mortgage bonds (a)
2.82 May 1, 2051100 — 
Other long-term debt— 
Unamortized discount(4)(4)
Unamortized debt issuance cost(10)(9)
Current maturities— (19)
Total long-term debt$987 $887 
(a)2021 financing.
(b)2020 financing.

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Maturities of long-term debt:
(Millions of Dollars)
Deferred Financing Costs — Deferred financing costs of approximately $10 million and $9 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2021 and 2020, respectively. NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.
Dividend Restrictions NSP-Wisconsin’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings.
NSP-Wisconsin’s state regulatory commission additionally imposes dividend limitations, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2021:
Equity to Total
Capitalization Ratio
Required Range
Equity to Total Capitalization Ratio Actual
52.5 %N/A52.8 %
Unrestricted Retained EarningsTotal Capitalization
Limit on Total Capitalization (a)
$11  million2,091 millionN/A
(a) NSP-Wisconsin cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
6. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Wisconsin’s operating revenues consisted of the following:
Year Ended Dec. 31, 2021
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$272 $91 $— $363 
C&I441 85 — 526 
Total retail721 176 898 
Interchange189 — — 189 
Other— — 
Total revenue from contracts with customers910 180 1,091 
Alternative revenue and other12 — 14 
Total revenues$922 $182 $$1,105 
Year Ended Dec. 31, 2020
(Millions of Dollars)ElectricNatural GasTotal
Major revenue types
Revenue from contracts with customers:
Residential$258 $64 $322 
C&I411 49 460 
Total retail675 113 788 
Interchange168 — 168 
Total revenue from contracts with customers843 117 960 
Alternative revenue and other12 14 
Total revenues$855 $119 $974 
Year Ended Dec. 31, 2019
(Millions of Dollars)ElectricNatural GasTotal
Major revenue types
Revenue from contracts with customers:
Residential$240 $73 $313 
C&I409 57 466 
Total retail655 130 785 
Interchange177 — 177 
Total revenue from contracts with customers833 134 967 
Alternative revenue and other12 14 
Total revenues$845 $136 $981 
7. Income Taxes
Federal Tax Loss Carryback Claims In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment.
Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s)Expiration
2014 - 2016December 2022
2018September 2022
Additionally, the statute of limitations related to certain federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

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State Audits — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2021, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2016. In March 2021, Wisconsin began an audit of tax years 2016 - 2019. As of Dec. 31, 2021 no material adjustments have been proposed.
Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.
Unrecognized tax benefits — permanent vs. temporary:
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions$$
Unrecognized tax benefit — Temporary tax positions
Total unrecognized tax benefit$$
Changes in unrecognized tax benefits:
(Millions of Dollars)202120202019
Balance at Jan. 1$$$
Additions for tax positions of prior years— 
Reductions for tax positions of prior years— (2)— 
Balance at Dec. 31$$$
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
NOL and tax credit carryforwards$(2)$(2)
As the IRS progresses its review of the tax loss carryback claims and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. Payables for interest related to unrecognized tax benefits at Dec. 31, 2021, 2020 and 2019 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2021, 2020 or 2019.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: