Northern States Power 10-K 2021 FY Annual report

0001123852nspm:RegulatedNaturalGasSegmentMemberus-gaap:IntersegmentEliminationMember2020-01-012020-12-31

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2021 or

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

For the transition period from _____ to _____

001-31387

(Commission File Number)

Northern States Power Company

(Exact name of registrant as specified in its charter)

Minnesota			41-1967505
(State or Other Jurisdiction of Incorporation or Organization)			(IRS Employer Identification No.)
414 Nicollet Mall	Minneapolis	Minnesota	55401
(Address of Principal Executive Offices)			(Zip Code)

(612)	330-5500
(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act: 

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

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, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 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).

TABLE OF CONTENTS

PART I
Item 1 —	Business	3
Item 1A —	Risk Factors	9
Item 1B —	Unresolved Staff Comments	15
Item 2 —	Properties	16
Item 3 —	Legal Proceedings	16
Item 4 —	Mine Safety Disclosures	17
PART II
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6 —	[Reserved]	17
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	21
Item 8 —	Financial Statements and Supplementary Data	23
Item 9 —	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	54
Item 9A —	Controls and Procedures	54
Item 9B —	Other Information	55
Item 9C —	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	55
PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	55
Item 11 —	Executive Compensation	55
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	55
Item 14 —	Principal Accountant Fees and Services	55
PART IV
Item 15 —	Exhibit and Financial Statement Schedules	56
Item 16 —	Form 10-K Summary	58
Signatures		59

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

2

PART I

Item l — Business

Definitions of Abbreviations

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

Federal and State Regulatory Agencies
DOC	Minnesota Department of Commerce
DOE	United States Department of Energy
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPUC	Minnesota Public Utilities Commission
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
PHMSA	Pipeline and Hazardous Materials Safety Administration
SEC	Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
DSM	Demand side management
FCA	Fuel clause adjustment
GUIC	Gas utility infrastructure cost rider
RES	Renewable energy standard
TCR	Transmission cost recovery adjustment

Other
AFUDC	Allowance for funds used during construction
ALJ	Administrative Law Judge
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
C&I	Commercial and Industrial
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CCR	Coal combustion residuals
CCR Rule	Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CEO	Chief executive officer
CFO	Chief financial officer
CON	Certificate of Need
COVID-19	Novel coronavirus

CWA	Clean Water Act
CWIP	Construction work in progress
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
ELG	Effluent limitations guidelines
EMANI	European Mutual Association for Nuclear Insurance
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GE	General Electric
GHG	Greenhouse gas
INPO	Institute of Nuclear Power Operations
IPP	Independent power producing entity
ISO	Independent System Operators
ITC	Investment tax credit
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
Native load	Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract
NAV	Net asset value
NEIL	Nuclear Electric Insurance Ltd.
NOL	Net operating loss
NOPR	Notice of proposed rulemaking
O&M	Operating and maintenance
OAG	Minnesota Office of the Attorney General
PFAS	Per- and PolyFluoroAlkyl Substances
PI	Prairie Island nuclear generating plant
PPA	Purchased power agreement
PTC	Production tax credit
REC	Renewable energy credit
ROE	Return on equity
ROU	Right-of-use
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Global Ratings
SERP	Supplemental executive retirement plan
TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
TO	Transmission owner
VaR	Value at Risk
VIE	Variable interest entity

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

3

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-Minnesota 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 of government restrictions, and sales volatility; operational safety, including our nuclear generation facilities; 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 Code 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-Minnesota 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-Minnesota is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. 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 http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.

Company Overview

Electric customers	1.5 million		NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.
Natural gas customers	0.5 million
Total assets	$22.8 billion
Rate Base (estimated)	$13.7 billion
ROE (net income / average stockholder's equity)	8.45%
Electric generating capacity	8,628 MW
Gas storage capacity	17.1 Bcf
Electric transmission lines (conductor miles)	34,155 miles
Electric distribution lines (conductor miles)	81,406 miles
Natural gas transmission lines	85 miles
Natural gas distribution lines	10,741 miles

4

Electric Operations

Electric operations consist of energy supply, generation, transmission and distribution activities. NSP-Minnesota had electric sales volume of 45,269 (millions of KWh), 1.5 million customers and electric revenues of $5,094 (millions of dollars) for 2021.

Retail Sales/Revenue Statistics (a)

	2021			2020
KWH sales per retail customer	21,644			21,440
Revenue per retail customer	$	2,507		$	2,306
Residential revenue per KWh	13.7		¢	13.36		¢
Large C&I revenue per KWh	8.96		¢	7.93		¢
Small C&I revenue per KWh	11.34		¢	10.24		¢
Total retail revenue per KWh	11.58		¢	10.76		¢

(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

Wind

Owned — Owned and operated wind farms with corresponding capacity:

2021		2020
Wind Farms	Capacity (a)	Wind Farms	Capacity (b)
14	2,031 MW	11	1,540 MW

(a)Summer 2021 net dependable capacity.

(b)Summer 2020 net dependable capacity.

PPAs — Number of PPAs with capacity range:

2021		2020
PPAs	Range	PPAs	Range
128	1 MW — 206 MW	129	1 MW — 206 MW

Capacity — Wind capacity:

2021	2020
3,997 MW	3,348 MW

5

Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:

2021		2020
$	25	$	23

Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:

2021		2020
$	37	$	38

Wind Development

The NSP System placed approximately 500 MW of owned wind and approximately 255 MW of PPAs into service during 2021:

Project	Capacity (MW)
Blazing Star 2	200 (a)(b)
Freeborn	200 (a)(b)
Mower	91 (a)(b)
PPA	~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.

Project	Capacity (MW)	Estimated Completion
Northern Wind	100	2022
Nobles	200	2022
Dakota Range	300	2022 (a)
Grand Meadow	100	2023
Border Winds	150	2025
Pleasant Valley	200	2025
Various PPAs	~200	2022

(a) Placed in service in January 2022.

Solar

Solar PPA(s):

Type	Capacity (MW)
Distributed Generation	994
Utility-Scale	268
Total	1,262

Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:

2021		2020
$	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.

Nuclear

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:

	Nuclear
	Cost		Percent
2021	$	0.77	46	%
2020	0.80		51

Other

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.

Coal

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:

Year	Plant Unit	Capacity (MW)
2023	Sherco 2	682
2026	Sherco 1	680
2028	A.S. King	511
2030	Sherco 3	517 (a)

(a)    Based on the NSP System’s ownership interest.

Coal Fuel Cost

Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:

	Coal (a)
	Cost		Percent
2021	$	1.60	39	%
2020	1.97		31

(a)    Includes refuse-derived fuel and wood.

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.

6

Natural Gas Cost

Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements:

	Natural Gas
	Cost		Percent
2021 (a)	$	4.98	15	%
2020	2.67		17

(a)Reflective of Winter Storm Uri.

Capacity and Demand

Uninterrupted system peak demand and occurrence date:

System Peak Demand (MW)
2021		2020
8,837	June 9	8,571	July 8

Transmission

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-Minnesota owns more than 34,000 conductor miles of transmission lines across its service territory.

Transmission projects completed in 2021 include:

Project	Miles	Size (KV)
Hibbing Taconite Relocation	3	500
Huntley - Wilmarth	50	345
Helena Scott County	16	345
Centerville to Lincoln County	14	69

Notable upcoming projects:

Project	Miles	Size (KV)	Completion Date
Baytown to Long Lake	9	115	2022
Bird Island - Atwater - Big Swan	68	69	2022
Pipestone - Tracy	46	69	2022
Line Rebuild - Central	24	69	2022
West St. Cloud to Millwood Tap	24	69	2022

See Item 2 - Properties for further information.

Distribution

Distribution lines allow electricity to travel at lower voltages from substations directly to customers. NSP-Minnesota has a vast distribution network, owning and operating approximately 81,000 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-Minnesota had natural gas deliveries of 94,802 (thousands of MMBtu), 0.5 million customers and natural gas revenues of $623 (millions of dollars) for 2021.

Sales/Revenue Statistics (a)

	2021		2020
MMBtu sales per retail customer	149		159
Revenue per retail customer	$	1,121	$	902
Residential revenue per MMBtu	8.56		6.66
C&I revenue per MMBtu	6.53		4.69
Transportation and other revenue per MMBtu	1.29		0.97

(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		2020
MMBtu	Date (a)	MMBtu	Date
899,133	Feb. 11	871,921	Jan. 16

(a)Reflective of Winter Storm Uri.

7

Natural Gas Supply and Costs

NSP-Minnesota seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility and decreases interruption and financial risks and economical rates. In addition, NSP-Minnesota 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)		2020
$	7.48	$	3.32

(a)Reflective of Winter Storm Uri.

NSP-Minnesota 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.

General

Seasonality

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-Minnesota’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

Competition

NSP-Minnesota is subject to public policies that promote competition and development of energy markets. NSP-Minnesota’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.

Minnesota has incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to NSP-Minnesota’s electric service business with these incentives and federal tax subsidies.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. NSP-Minnesota’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission system of NSP-Minnesota on a comparable basis to serve their native load.

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-Minnesota 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-Minnesota 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-Minnesota activities require registrations, permits, licenses, inspections and approvals from these agencies. NSP-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices. NSP-Minnesota 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-Minnesota will continue to monitor these regulatory developments and their potential impact on its operations.

8

Other

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.

Employees

As of Dec. 31, 2021, NSP-Minnesota had 3,083 full-time employees and five part-time employees, of which 2,020 were covered under collective-bargaining agreements.

ITEM 1A — RISK FACTORS

Xcel Energy, which includes NSP-Minnesota, 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 Xcel Energy files 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-Minnesota’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-Minnesota 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-Minnesota 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-Minnesota. 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-Minnesota'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.

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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 these 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.

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-Minnesota 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-Minnesota 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-Minnesota’s results of operations, financial condition or cash flows could be materially impacted.

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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.

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-Minnesota 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.

We are subject to the risks of nuclear generation.

NSP-Minnesota has two nuclear generation plants, PI 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 our 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 our compliance costs.

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 $431 million, $408 million and $467 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-Minnesota is imposed by our state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.

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 both future and historical test years depending upon the regulatory jurisdiction. 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.

The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission our nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.

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 in our short-term wholesale and commodity trading 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., Southwest Power Pool, Inc., PJM Interconnection, LLC, MISO and Electric Reliability Council of Texas), 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 S&P or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 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-Minnesota could trigger settlement accounting and could require NSP-Minnesota to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. 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-Minnesota 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-Minnesota 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.

NSP-Minnesota has experienced and may continue to experience sales volatility and shifts between residential and C&I sales as a result of COVID-19. NSP-Minnesota has historically had a sales true-up mechanism for all electric customer classes which has ended in 2021. We are requesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of changes to sales levels as compared to a baseline.

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.

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NSP-Minnesota 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.

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 NSP-Minnesota 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-Minnesota 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.

ITEM 1B — UNRESOLVED STAFF COMMENTS

None.

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ITEM 2 — PROPERTIES

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

Station, Location and Unit at Dec. 31, 2021	Fuel	Installed	MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit (f)	Coal	1968	511
Sherco-Becker, MN (e)
Unit 1	Coal	1976	680
Unit 2	Coal	1977	682
Unit 3	Coal	1987	517	(b)
Monticello, MN, 1 Unit	Nuclear	1971	617
PI-Welch, MN
Unit 1	Nuclear	1973	521
Unit 2	Nuclear	1974	519
Various locations, 4 Units	Wood/Refuse	Various	36	(c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 Units	Natural Gas	1994 - 2005	327
Black Dog-Burnsville, MN, 3 Units	Natural Gas	1987 - 2018	494
Blue Lake-Shakopee, MN, 6 Units	Natural Gas	1974 - 2005	447
High Bridge-St. Paul, MN, 3 Units	Natural Gas	2008	530
Inver Hills-Inver Grove Heights, MN, 6 Units	Natural Gas	1972	252
Riverside-Minneapolis, MN, 3 Units	Natural Gas	2009	454
Various locations, 7 Units	Natural Gas	Various	10
Wind:
Blazing Star 1-Lincoln County, MN, 100 Units	Wind	2020	200	(d)
Blazing Star 2-Lincoln County, MN, 100 Units	Wind	2021	200	(d)
Border-Rolette County, ND, 75 Units	Wind	2015	148	(d)
Community Wind North-Lincoln County, MN, 12 Units	Wind	2020	26	(d)
Courtenay Wind-Stutsman County, ND, 100 Units	Wind	2016	190	(d)
Crowned Ridge 2-Grant County, SD, 88 Units	Wind	2020	192	(d)
Foxtail-Dickey County, ND, 75 Units	Wind	2019	150	(d)
Freeborn-Freeborn County, MN, 100 Units	Wind	2021	200	(d)
Grand Meadow-Mower County, MN, 67 Units	Wind	2008	99	(d)
Jeffers-Cottonwood County, MN, 20 Units	Wind	2020	43	(d)
Lake Benton-Pipestone County, MN, 44 Units	Wind	2019	99	(d)
Mower-Mower County, MN, 43 Units	Wind	2021	91	(d)
Nobles-Nobles County, MN, 134 Units	Wind	2010	197	(d)
Pleasant Valley-Mower County, MN, 100 Units	Wind	2015	196	(d)
		Total	8,628

(a)Summer 2021 net dependable capacity.

(b)Based on NSP-Minnesota’s ownership of 59%.

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

(d)Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).

(e)A.S. King is expected to be retired early in 2028.

(f)Sherco Unit 1, 2, and 3 are expected to be retired early in 2026, 2023 and 2030, respectively.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2021:

Conductor Miles
Transmission
500 KV	2,915
345 KV	13,570
230 KV	2,300
161 KV	640
115 KV	8,086
Less than 115 KV	6,644
Total Transmission	34,155
Distribution
Less than 115 KV	81,406
Total	115,561

NSP-Minnesota had 354 electric utility transmission and distribution substations at Dec. 31, 2021.

Natural gas utility mains at Dec. 31, 2021:

Miles
Transmission	85
Distribution	10,741

ITEM 3 — LEGAL PROCEEDINGS

NSP-Minnesota 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-Minnesota’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.

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ITEM 4 — MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

NSP-Minnesota 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)	2021		2020
First quarter	$	109	$	100
Second quarter	107		105
Third quarter	109		109
Fourth quarter	96		106

ITEM 6 — [RESERVED]

ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in General Instruction 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-Minnesota’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-Minnesota. For the years ended Dec. 31, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.

Results of Operations

2021 Comparison with 2020

NSP-Minnesota’s net income was approximately $606 million for 2021, compared with approximately $591 million for 2020. The increase in earnings primarily reflects capital investment recovery offset by additional depreciation and interest charges.

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 PTCs generated, which reduce electric revenue and income taxes.

Electric Revenues, Fuel and Purchased Power and Electric Margin

(Millions of Dollars)	2021		2020
Electric revenues	$	5,094	$	4,571
Electric fuel and purchased power	(2,042)		(1,626)
Electric margin	$	3,052	$	2,945

Changes in Electric Margin

(Millions of Dollars)	2021 vs. 2020
Non-fuel riders	$	118
Conservation program revenues (offset in expense)	24
Proprietary commodity trading, net of sharing (a)	20
Interchange agreement billings with NSP-Wisconsin	18
PTCs flowed back to customers (offset by lower ETR)	(60)
Wholesale transmission revenue (net)	(21)
Other (net)	8
Total increase in electric margin	$	107

(a)Includes $12 million of net gains recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri. Additional amounts are primarily related to long-term physical generation contracts, which have increased in value as a result of higher energy prices.

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.

17

Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin

(Millions of Dollars)	2021		2020
Natural gas revenues	$	623	$	493
Cost of natural gas sold and transported	(385)		(263)
Natural gas margin	$	238	$	230

Changes in Natural Gas Margin

(Millions of Dollars)	2021 vs. 2020
Infrastructure and integrity riders	$	7
Estimated impact of weather	(2)
Other (net)	3
Total increase in natural gas margin	$	8

Non-Fuel Operating Expenses and Other Items

Depreciation and Amortization — Depreciation and amortization expense increased $101 million for 2021. The increase was primarily driven by several wind farms going into service, as well as normal system expansion.

Interest Charges — Interest charges increased $22 million year-to-date. The increase was largely due to higher debt levels to fund capital investments, partially offset by lower long-term and short-term interest rates.

Income Taxes — Income tax benefit increased $42 million for 2021. The increase was primarily driven by increased wind PTCs. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.

Other

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-Minnesota incurred net natural gas, fuel and purchased energy costs of approximately $230 million (largely deferred as regulatory assets).

Regulatory Overview — NSP-Minnesota has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, NSP-Minnesota has deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 63 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.

Proceedings initiated:

Jurisdiction	Regulatory Status
Minnesota	NSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. In August 2021, the MPUC allowed recovery of $179 million of costs deemed to be extraordinary beginning in September 2021 over 27 months (no financing charge) and $36 million of ordinary costs over 12 months through the monthly Purchased Gas Adjustment. The $179 million in extraordinary cost recovery is subject to refund pending the outcome of a contested case before an ALJ. In December 2021, the MPUC approved extending recovery of Winter Storm Uri costs for the residential class (approximately $97 million) from a 27-month recovery period to a 63-month recovery period. New residential Winter Storm Uri rates were effective Jan. 1, 2022. In December 2021, direct testimony was received from intervenors. The DOC recommended a $127 million disallowance based on allegations including peaking plant usage, load forecasting, natural gas supply/storage and related purchases. Alternatively, the DOC recommended a $42 million disallowance if NSP-Minnesota proves it prudently managed its peaking plants. The OAG recommended a disallowance of $179 million based on allegations that NSP-Minnesota could have fully hedged its exposure to spot market prices. Alternatively, the OAG recommended a $25 million disallowance based on allegations related to specific hedges allegedly available in the market during February 2021. The CUB recommended a $69 million disallowance based on allegations related to the unavailability of NSP-Minnesota’s peaking plants, inaccuracy of load forecasting and inadequate curtailment of interruptible customers. Xcel Energy strongly disagrees with the recommendations of the DOC, OAG and CUB and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota intends to file rebuttal testimony in January 2022. A hearing before the ALJs assigned to the matter is scheduled for Feb. 17-23, 2022. An MPUC decision is expected in the summer of 2022. See Rate Matters and Other within Note 10 to the consolidated financial statements for further information.
South Dakota	Winter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the electric market.
North Dakota	In June, the NDPSC approved recovery of $32 million in natural gas costs over 15 months (starting July 2021) with no financing charge.

Public Utility Regulation

The FERC and various state and local regulatory commissions regulate NSP-Minnesota. NSP-Minnesota 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 Minnesota, North Dakota and South Dakota.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. NSP-Minnesota requests changes in utility rates through commission filings. Changes in operating costs can affect NSP-Minnesota’s financial results, depending on the timing of rate cases 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-Minnesota’s results of operations.

See Rate Matters within Note 10 to the consolidated financial statements for further information.

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Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO	Additional Information
MPUC	Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Pipeline safety compliance.
NDPSC	Retail rates, services and other aspects of electric and natural gas operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance.
South Dakota Public Utilities Commission	Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance.
FERC	Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.
MISO	NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.
DOT	Pipeline safety compliance.
Minnesota Office of Pipeline Safety	Pipeline safety compliance.

Recovery Mechanisms

Mechanism	Additional Information
CIP Rider (a)	Recovers costs of conservation and DSM programs in Minnesota.
Environmental Improvement Rider	Recovers costs of environmental improvement projects in Minnesota.
Renewable Development Fund	Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.
RES	Recovers cost of renewable generation in Minnesota.
Renewable Energy Rider	Recovers cost of renewable generation in North Dakota.
State Energy Policy Rider	Recovers costs related to various energy policies approved by the Minnesota legislature.
TCR	Recovers costs for investments in electric transmission and distribution grid modernization.
Infrastructure Rider	Recovers costs for investments in generation and incremental property taxes in South Dakota.
FCA (b)	Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. MISO costs are generally recovered through either the FCA or base rates.
Purchased Gas Adjustment	Provides for prospective monthly rate adjustments for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.
GUIC Rider	Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.
Sales True-up	In February 2022, NSP-Minnesota filed the 2021 sales true-up compliance report, resulting in a total surcharge of $59 million. An MPUC ruling is anticipated in the second quarter of 2022. In their current rate case, NSP-Minnesota has proposed a sales true-up mechanism for 2022 and beyond that would operate similarly to the 2021 sales true-up. Under the stay-out petition, 2021 NSP-Minnesota jurisdictional earnings was capped at a 9.06% ROE. Any excess earnings are required to be refunded to customers.

(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.

(b)The MPUC changed the FCA process in Minnesota (effective in 2020). Each month, utilities collect amounts equal to baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to baseline costs are tracked and netted over a 12-month period. Utilities issue refunds above the baseline costs and can seek recovery of any overage.

Pending and Recently Concluded Regulatory Proceedings

2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, rate base of $934 million and an equity ratio of 52.50%.

In December 2021, the MPUC approved the requested interim rates of $25 million, subject to refund, beginning on Jan. 1, 2022.

The next steps in the procedural schedule are expected to be as follows:

•Intervenor testimony: Aug. 30, 2022

•Rebuttal testimony: Oct. 4, 2022

•Public hearing: Nov. 1-4, 2022

•ALJ Report: Feb. 6, 2023

•MPUC Order: April 26, 2023

19

2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years.

The request is detailed as follows:

(Amounts in Millions, Except Percentages)	2022			2023			2024			Total
Rate request	$	396		$	150		$	131		$	677
Increase percentage	12.2		%	4.8		%	4.2		%	21.2		%
Rate base	$	10,931		$	11,446		$	11,918		N/A

In addition, NSP-Minnesota requested interim rates, subject to refund, of $288 million to be implemented in January 2022 and an incremental $135 million to be implemented in January 2023. In December 2021, the MPUC approved rates of $247 million to begin on Jan. 1, 2022. The adjusted level reflects exigent circumstances from the COVID-19 pandemic.

The next steps in the procedural schedule are expected to be as follows:

•Intervenor testimony: Oct. 3, 2022

•Rebuttal testimony: Nov. 8, 2022

•Public hearing: Dec. 13-16, 2022

•ALJ Report: March 31, 2023

•MPUC Order: June 30, 2023

2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.49%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a rate base of approximately $140 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021. An NDPSC decision is expected in early fall 2022.

The next steps in the procedural schedule are expected to be as follows:

•Intervenor testimony: March 1, 2022

•Rebuttal testimony: April 1, 2022

•Hearings: June 1-3, 2022

2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a rate case with the NDPSC seeking a rate increase of $19 million based on a ROE of 10.2%, an equity ratio of 52.5% and rate base of $677 million.

In August 2021, the NDPSC approved a settlement between NSP-Minnesota and various parties, which includes the following, effective Jan. 1, 2021:

•Base revenue increase of $7 million.

•ROE of 9.5%.

•Equity ratio of 52.5%.

•Deferral of advanced grid intelligence and security initiative capital and O&M expenses.

•An earnings cap mechanism, which would return to customers 100% of earnings equal to or in excess of 9.75% ROE, effective until the next rate case.

Minnesota Relief and Recovery — In 2020, the MPUC opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19.

The status of the various proposals is listed below:

•In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years.

•In April 2021, 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.

•In June 2021, the MPUC approved NSP-Minnesota’s proposal to acquire a repowered wind farm from ALLETE, Inc.

•The MPUC is also considering NSP-Minnesota’s revised proposal to provide $40 million of incremental electric vehicle rebates.

Minnesota Resource Plan — In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034.

On Feb. 8, 2022, the MPUC approved the following:

•10-year extension for the Monticello nuclear facility.

•Retirement of the A.S. King plant in 2028 and Sherco 3 in 2030.

•NSP-Minnesota ownership of Sherco and A.S. King gen-tie lines plus additional renewable resources on the lines up to its current interconnection rights (2,000 MW for Sherco and 600 MW for A.S. King).

•The need for 2,150 MW of new wind and 2,500 MW of new solar by 2032, as well as additional renewable generation of 1,100 MW beyond 2032.

•Recognition of the need for 800 MW of additional firm dispatchable resources between 2027 and 2029. The dispatchable generation will need to be approved through a CON process.

The next Minnesota resource plan is due on Feb. 1, 2024.

2022 RES Electric Rider — In November 2021, NSP-Minnesota filed the RES Rider. The requested amount of $264 million includes a true-up (2020 and 2021 riders) of $154 million and the 2022 requested amount of $110 million. The filing included a ROE of 9.06%. An MPUC decision is pending.

2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount of $189 million includes a true-up (2019 and 2020 riders) of $96 million and the 2021 requested amount of $93 million. The filing included a ROE of 9.06%. An MPUC decision is pending.

2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An MPUC decision is pending.

2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An MPUC decision is pending.

2022 TCR Electric Rider — In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million based on a ROE of 9.06%. An MPUC decision is pending.

2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider for an amount of $82 million based on a ROE of 9.06%, which was approved by the MPUC in December 2021.

20

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 Arrangements and Transmission Service Provider

NSP-Minnesota expects to use power plants, power purchases, CIP/DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a capacity 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.

Nuclear Power Operations

Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.

NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.

Low-Level Waste Disposal — Low level waste disposal from Monticello and PI is disposed at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.

High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.

Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.

Monticello CON — In September 2021, NSP-Minnesota filed an application for a CON for additional spent fuel storage (existing Independent spent fuel storage installation) at the Monticello Nuclear Power Generating Plant. The CON requests sufficient additional spent fuel storage at the existing Independent spent fuel storage installation to allow continued operation of the Monticello Plant until 2040. The filing passed completeness review and has been referred to an ALJ. A decision is expected in late 2023.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.

NSP-Minnesota also engages in trading activity unrelated to hedging. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivatives, Risk Management and Market Risk

NSP-Minnesota 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-Minnesota 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-Minnesota expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose NSP-Minnesota to certain credit and non-performance risk.

Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and NSP-Minnesota’s ability to earn a return on short-term investments.

Commodity Price Risk — NSP-Minnesota 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 electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. NSP-Minnesota’s risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

21

Fair value of net commodity trading contracts as of Dec. 31, 2021:

	Futures/ Forwards Maturity
(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)		$	(4)	$	(7)	$	—	$	(1)	$	(12)
NSP-Minnesota (b)		(1)		3		(9)		(8)		(15)
		$	(5)	$	(4)	$	(9)	$	(9)	$	(27)

	Options Maturity
(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)		$	1	$	—	$	—	$	8	$	9

(a)Prices actively quoted or based on actively quoted prices.

(b)Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:

(Millions of Dollars)	2021		2020
Fair value of commodity trading net contracts outstanding at Jan. 1	$	(8)	$	(2)
Contracts realized or settled during the period	(58)		(11)
Commodity trading contract additions and changes during the period	48		5
Fair value of commodity trading net contracts outstanding at Dec. 31	$	(18)	$	(8)

At Dec. 31, 2021, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $3 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $3 million. At Dec. 31, 2020, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $6 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $6 million. Market price movements can exceed 10% under abnormal circumstances.

NSP-Minnesota’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

(Millions of Dollars)	Year Ended Dec. 31		VaR Limit		Average		High		Low
2021	$	1	$	3	$	2	$	52	$	1
2020	1		3		1		2		1

A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this widespread weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.

Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 78% of its 2022 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impact the supply of enriched nuclear material supplied from Russia. Long-term, through 2030, NSP-Minnesota is scheduled to take delivery of approximately 30% of its average enriched nuclear material requirements from these sources. NSP-Minnesota is able to manage nuclear fuel supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.

Interest Rate Risk — NSP-Minnesota is subject to interest rate risk. NSP-Minnesota’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-Minnesota’s variable rate debt would impact pretax interest expense annually by an immaterial amount in 2021 and 2020, respectively.

NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting.

Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.

See Note 8 to the consolidated financial statements for further information.

Credit Risk — NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. NSP-Minnesota 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, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $28 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $18 million. At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $9 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $1 million.

22

NSP-Minnesota 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-Minnesota’s credit risk.

Fair Value Measurements

NSP-Minnesota uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value.

NSP-Minnesota’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.

Commodity Derivatives — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2021.

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2021.

See Notes 8 and 9 to the consolidated financial statements for further information.

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

See Note 14 to the consolidated financial statements for further information.

23

Management Report on Internal Control Over Financial Reporting

The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Minnesota’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and NSP-Minnesota’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-Minnesota management assessed the effectiveness of NSP-Minnesota’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-Minnesota’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ ROBERT C. FRENZEL	/s/ BRIAN J. VAN ABEL
Robert C. Frenzel	Brian J. Van Abel
Chairman, Chief Executive Officer and Director	Executive Vice President, Chief Financial Officer and Director
Feb. 23, 2022	Feb. 23, 2022

24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Northern States Power Company, a Minnesota corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Northern States Power Company, a Minnesota 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 distribution companies in Minnesota, North Dakota and South Dakota, and natural gas distribution companies in Minnesota and North Dakota. 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.

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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.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 23, 2022

We have served as the Company’s auditor since 2002.

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions)

	Year Ended Dec. 31
	2021		2020		2019
Operating revenues
Electric, non-affiliates	$	4,593	$	4,131	$	4,049
Electric, affiliates	501		440		457
Natural gas	623		493		571
Other	39		37		35
Total operating revenues	5,756		5,101		5,112
Operating expenses
Electric fuel and purchased power	2,042		1,626		1,601
Cost of natural gas sold and transported	385		263		327
Cost of sales — other	23		22		23
Operating and maintenance expenses	1,190		1,191		1,203
Conservation program expenses	144		119		120
Depreciation and amortization	926		825		791
Taxes (other than income taxes)	264		259		260
Total operating expenses	4,974		4,305		4,325
Operating income	782		796		787
Other income (expense), net	4		2		(1)
Allowance for funds used during construction — equity	30		25		25
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8 and $7, respectively	271		249		233
Allowance for funds used during construction — debt	(13)		(11)		(12)
Total interest charges and financing costs	258		238		221
Income before income taxes	558		585		590
Income tax (benefit) expense	(48)		(6)		47
Net income	$	606	$	591	$	543
See Notes to Consolidated Financial Statements

27

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

	Year Ended Dec. 31
	2021		2020		2019
Net income	$	606	$	591	$	543
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $—	2		1		—
Total other comprehensive income	2		1		—
Total comprehensive income	$	608	$	592	$	543
See Notes to Consolidated Financial Statements

28

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)

	Year Ended Dec. 31
	2021		2020		2019
Operating activities
Net income	$	606	$	591	$	543
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	932		831		798
Nuclear fuel amortization	114		123		119
Deferred income taxes	(36)		(67)		(39)
Allowance for equity funds used during construction	(30)		(25)		(25)
Provision for bad debts	24		24		13
Changes in operating assets and liabilities:
Accounts receivable	(89)		(55)		15
Accrued unbilled revenues	(71)		1		20
Inventories	(22)		(14)		(29)
Other current assets	3		(9)		(3)
Accounts payable	69		(1)		(13)
Net regulatory assets and liabilities	(282)		(87)		(140)
Other current liabilities	(5)		(58)		(12)
Pension and other employee benefit obligations	(41)		(54)		(49)
Other, net	(50)		(8)		(29)
Net cash provided by operating activities	1,122		1,192		1,169
Investing activities
Capital/construction expenditures	(1,866)		(1,901)		(1,417)
Purchase of investment securities	(757)		(1,398)		(995)
Proceeds from the sale of investment securities	743		1,378		975
Investments in utility money pool arrangement	(821)		(718)		(219)
Repayments from utility money pool arrangement	730		718		219
Other, net	1		1		(3)
Net cash used in investing activities	(1,970)		(1,920)		(1,440)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(179)		149		(120)
Borrowings under utility money pool arrangement	434		136		696
Repayments under utility money pool arrangement	(434)		(136)		(696)
Proceeds from issuance of long-term debt	836		677		580
Repayment of long-term debt	—		(300)		—
Capital contributions from parent	649		527		354
Dividends paid to parent	(431)		(408)		(467)
Other, net	—		3		—
Net cash provided by financing activities	875		648		347
Net change in cash, cash equivalents and restricted cash	27		(80)		76
Cash, cash equivalents and restricted cash at beginning of period	46		126		50
Cash, cash equivalents and restricted cash at end of period	$	73	$	46	$	126
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(245)	$	(230)	$	(209)
Cash received (paid) for income taxes, net	11		(53)		(105)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	242	$	74	$	95
Inventory transfers to property, plant and equipment	8		24		24
Operating lease right-of-use assets	4		2		629
Allowance for equity funds used during construction	30		25		25
See Notes to Consolidated Financial Statements

29

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2021		2020
Assets
Current assets
Cash and cash equivalents	$	73	$	46
Accounts receivable, net	429		392
Accounts receivable from affiliates	29		32
Investments in money pool arrangements	91		—
Accrued unbilled revenues	319		248
Inventories	309		295
Regulatory assets	527		411
Derivative instruments	53		17
Prepayments and other	46		50
Total current assets	1,876		1,491
Property, plant and equipment, net	16,430		15,308
Other assets
Nuclear decommissioning fund and other investments	3,308		2,830
Regulatory assets	718		924
Derivative instruments	33		5
Operating lease right-of-use assets	408		488
Other	36		14
Total other assets	4,503		4,261
Total assets	$	22,809	$	21,060
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	300	$	—
Short-term debt	—		179
Accounts payable	522		438
Accounts payable to affiliates	63		66
Regulatory liabilities	117		123
Taxes accrued	260		263
Accrued interest	78		72
Dividends payable to parent	96		106
Derivative instruments	35		22
Operating lease liabilities	90		85
Other	166		154
Total current liabilities	1,727		1,508
Deferred credits and other liabilities
Deferred income taxes	1,949		1,840
Deferred investment tax credits	17		18
Regulatory liabilities	1,927		1,896
Asset retirement obligations	2,585		2,350
Derivative instruments	71		71
Pension and employee benefit obligations	112		192
Operating lease liabilities	353		443
Other	48		69
Total deferred credits and other liabilities	7,062		6,879
Commitments and contingencies	0		0
Capitalization
Long-term debt	6,447		5,904
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares    outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively	—		—
Additional paid in capital	5,202		4,585
Retained earnings	2,391		2,206
Accumulated other comprehensive loss	(20)		(22)
Total common stockholder's equity	7,573		6,769
Total liabilities and equity	$	22,809	$	21,060
See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in millions, except share data)

	Common Stock							Accumulated Other Comprehensive Income (Loss)		Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2018	1,000,000	$	—	$	3,624	$	1,972	$	(23)	$	5,573
Net income						543				543
Dividends declared to parent						(479)				(479)
Contribution of capital by parent				444						444
Balance at Dec. 31, 2019	1,000,000	$	—	$	4,068	$	2,036	$	(23)	$	6,081
Net income						591				591
Other comprehensive income								1		1
Dividends declared to parent						(420)				(420)
Contribution of capital by parent				517						517
Adoption of ASC Topic 326						(1)				(1)
Balance at Dec. 31, 2020	1,000,000	$	—	$	4,585	$	2,206	$	(22)	$	6,769
Net income						606				606
Other comprehensive income								2		2
Dividends declared to parent						(421)				(421)
Contribution of capital by parent				617						617
Balance at Dec. 31, 2021	1,000,000	$	—	$	5,202	$	2,391	$	(20)	$	7,573
See Notes to Consolidated Financial Statements

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NORTHERN STATES POWER COMPANY - MINNESOTA

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.

NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.

NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.

NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’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-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — NSP-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota’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-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota 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-Minnesota, 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.

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.

32

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-Minnesota 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. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.7% for 2021, 3.7% for 2020 and 3.7% for 2019.

See Note 3 for further information.

AROs — NSP-Minnesota 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.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every 3 years and submitted to the state commissions for approval.

NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Notes 8 and 10 for further information.

Benefit Plans and Other Postretirement Benefits — NSP-Minnesota 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-Minnesota 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-Minnesota’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-Minnesota 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-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees.

NSP-Minnesota recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.

NSP-Minnesota 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.

See Note 6 for further information.

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Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of 3 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-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2021 and 2020, the allowance for bad debts was $45 million and $33 million, respectively.

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
Inventories
Materials and supplies	$	181	$	178
Fuel	81		90
Natural gas	47		27
Total inventories	$	309	$	295

Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets 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-Minnesota may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, 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-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price and commodity trading 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.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — NSP-Minnesota 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.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.

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-Minnesota’s rate base for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) 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 incentives and return on rate base items.

Billing amounts are revised periodically for differences between total amount collected and revenue earned, 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 — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

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.

Nuclear Refueling Outage Costs — NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.

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. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.

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-Minnesota implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $1 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020 adoption of ASC Topic 326 did not have a significant impact on NSP-Minnesota’s consolidated financial statements.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
Property, plant and equipment, net
Electric plant	$	19,154	$	18,948
Natural gas plant	1,864		1,707
Common and other property	1,007		955
Plant to be retired (a)	719		136
CWIP	984		1,150
Total property, plant and equipment	23,728		22,896
Less accumulated depreciation	(7,606)		(7,898)
Nuclear fuel	3,081		2,970
Less accumulated amortization	(2,773)		(2,660)
Property, plant and equipment, net	$	16,430	$	15,308

(a)Includes regulator-approved retirements of Sherco Units 1, 2 and 3 and A.S. King.

Joint Ownership of Generation and Transmission Facilities

Jointly owned assets as of Dec. 31, 2021:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
Electric generation:
Sherco Unit 3	$	620	$	451	59	%
Sherco common facilities	178		108		80
Sherco substation	5		4		59
Electric transmission:
Grand Meadow	11		3		50
Huntley Wilmarth	48		1		50
CapX2020	952		127		51
Total (a)	$	1,814	$	694

(a)Projects additionally include $7 million in CWIP.

NSP-Minnesota’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

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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-Minnesota 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 Period	Dec. 31, 2021				Dec. 31, 2020
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	24	$	301	$	26	$	364
Deferred natural gas and electric energy/fuel costs		One to five years	138		190		8		18
Recoverable deferred taxes on AFUDC		Plant lives	—		114		—		113
Excess deferred taxes — TCJA	7	Various	10		113		10		122
Sales true-up and revenue decoupling		One to two years	33		56		101		28
Benson biomass PPA termination and asset purchase		Eight years	10		55		10		65
PI extended power uprate		13 years	4		46		3		49
Contract valuation adjustments (a)	1, 8	Term of related contract	18		34		16		48
Purchased power contracts costs		Term of related contract	6		27		4		32
Conservation programs (b)	1	One to two years	7		22		14		23
Laurentian biomass PPA termination		Two years	18		18		18		36
Nuclear refueling outage costs	1	One to two years	37		16		28		10
Losses on reacquired debt		Term of related debt	1		11		1		12
Environmental remediation costs	1, 10	Pending future rate cases	—		5		1		9
Renewable resources and environmental initiatives		One to two years	170		3		129		1
State commission adjustments		Plant lives	—		3		—		3
Gas pipeline inspection and remediation costs		One to two years	33		—		26		—
Net AROs (c)	1, 10	Various	—		(316)		—		(32)
Other		Various	18		20		16		23
Total regulatory assets			$	527	$	718	$	411	$	924

(a)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2021				Dec. 31, 2020
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	9	$	1,256	$	9	$	1,326
Plant removal costs	1, 10	Various	—		613		—		544
Renewable resources and environmental initiatives		Various	1		10		5		—
ITC deferrals	1	Various	—		7		—		8
Contract valuation adjustments (b)	1, 8	Less than one year	29		—		12		—
DOE Settlement		Less than one year	14		—		11		—
Deferred natural gas and electric energy/fuel costs		Less than one year	14		—		8		—
Other		Various	50		41		78		18
Total regulatory liabilities (c)			$	117	$	1,927	$	123	$	1,896

(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.

(b)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(c)Revenue subject to refund of $15 million and $17 million for 2021 and 2020, respectively, is included in other current liabilities.

At Dec. 31, 2021 and 2020, NSP-Minnesota’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, regulatory assets included $691 million and $399 million at Dec. 31, 2021 and 2020, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs (including those related to Winter Storm Uri), various renewable resources and certain environmental initiatives.

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5. Borrowings and Other Financing Instruments

Short-Term Borrowings

NSP-Minnesota 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.

Money pool borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2021		Year Ended Dec. 31
			2021			2020			2019
Borrowing limit	$	250	$	250		$	250		$	250
Amount outstanding at period end	—		—			—			—
Average amount outstanding	—		6			3			32
Maximum amount outstanding	—		236			116			250
Weighted average interest rate, computed on a daily basis	N/A		0.07		%	1.53		%	2.05		%
Weighted average interest rate at period end	N/A		N/A			N/A			N/A

Commercial Paper — Commercial paper outstanding:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2021			Year Ended Dec. 31
				2021			2020			2019
Borrowing limit	$	500		$	500		$	500		$	500
Amount outstanding at period end	—			—			179			30
Average amount outstanding	—			26			10			71
Maximum amount outstanding	13			317			179			317
Weighted average interest rate, computed on a daily basis	0.15		%	0.18		%	1.25		%	2.59		%
Weighted average interest rate at end of period	N/A			N/A			0.18			2.05

Letters of Credit — NSP-Minnesota uses 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 $9 million and $10 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use commercial paper programs to fulfill short-term funding needs, NSP-Minnesota 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 NSP-Minnesota’s 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)
2021		2020
47	%	47	%	$	100	2

(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-Minnesota would be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.

If NSP-Minnesota 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-Minnesota was in compliance with all financial covenants on its debt agreements.

NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2021 (in millions of dollars):

Credit Facility (a)		Drawn (b)		Available
$	500	$	9	$	491

(a)This credit facility matures in June 2024.

(b)Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the facility outstanding at Dec. 31, 2021 and 2020.

Bilateral Credit Agreement — In April 2021, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of Dec. 31, 2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.

Long-Term Borrowings and Other Financing Instruments

Generally, all property of NSP-Minnesota 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 the new issuance.

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Long term debt obligations for NSP-Minnesota as of Dec. 31 (in millions of dollars):

Financing Instrument	Interest Rate		Maturity Date	2021		2020
First mortgage bonds	2.15	%	Aug. 15, 2022	$	300	$	300
First mortgage bonds	2.60		May 15, 2023	400		400
First mortgage bonds	7.125		July 1, 2025	250		250
First mortgage bonds	6.50		March 1, 2028	150		150
First mortgage bonds (a)	2.25		April 1, 2031	425		—
First mortgage bonds	5.25		July 15, 2035	250		250
First mortgage bonds	6.25		June 1, 2036	400		400
First mortgage bonds	6.20		July 1, 2037	350		350
First mortgage bonds	5.35		Nov. 1, 2039	300		300
First mortgage bonds	4.85		Aug. 15, 2040	250		250
First mortgage bonds	3.40		Aug. 15, 2042	500		500
First mortgage bonds	4.125		May 15, 2044	300		300
First mortgage bonds	4.00		Aug. 15, 2045	300		300
First mortgage bonds	3.60		May 15, 2046	350		350
First mortgage bonds	3.60		Sept. 15, 2047	600		600
First mortgage bonds	2.90		March 1, 2050	600		600
First mortgage bonds (b)	2.60		June 1, 2051	700		700
First mortgage bonds (a)	3.20		April 1, 2052	425		—
Other long-term debt				3		—
Unamortized discount				(44)		(42)
Unamortized debt issuance cost				(62)		(54)
Current maturities				(300)		—
Total long-term debt				$	6,447	$	5,904

(a)2021 financing.

(b)2020 financing.

Maturities of long-term debt are as follows:

(Millions of Dollars)
2022	$	300
2023	400
2024	—
2025	250
2026	—

Deferred Financing Costs — Deferred financing costs of approximately $62 million and $54 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2021 and 2020, respectively.

Dividend Restrictions — NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings.

NSP-Minnesota’s state regulatory commissions additionally impose 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
Low		High		2021
47.2	%	57.6	%	52.9	%

Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization
$	1,558	million	$	14,321	million	$	15,332	million

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consisted of the following:

	Year Ended Dec. 31, 2021
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,374	$	315	$	33	$	1,722
C&I	2,107		246		—		2,353
Other	33		—		6		39
Total retail	3,514		561		39		4,114
Wholesale	442		—		—		442
Transmission	242		—		—		242
Interchange	501		—		—		501
Other	7		14		—		21
Total revenue from contracts with customers	4,706		575		39		5,320
Alternative revenue and other	388		48		—		436
Total revenues	$	5,094	$	623	$	39	$	5,756

	Year Ended Dec. 31, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,375	$	261	$	31	$	1,667
C&I	1,935		189		—		2,124
Other	33		—		6		39
Total retail	3,343		450		37		3,830
Wholesale	202		—		—		202
Transmission	238		—		—		238
Interchange	440		—		—		440
Other	15		7		—		22
Total revenue from contracts with customers	4,238		457		37		4,732
Alternative revenue and other	333		36		—		369
Total revenues	$	4,571	$	493	$	37	$	5,101

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	Year Ended Dec. 31, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,280	$	303	$	30	$	1,613
C&I	2,054		229		—		2,283
Other	33		—		5		38
Total retail	3,367		532		35		3,934
Wholesale	210		—		—		210
Transmission	216		—		—		216
Interchange	459		—		—		459
Other	12		9		—		21
Total revenue from contracts with customers	4,264		541		35		4,840
Alternative revenue and other	242		30		—		272
Total revenues	$	4,506	$	571	$	35	$	5,112

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. As a result, a tax benefit of approximately $13 million was recognized in 2020.

Federal Audit — NSP-Minnesota 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 - 2016	December 2022
2018	September 2022

Additionally, the statute of limitations related to the 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.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2021, NSP-Minnesota’s earliest open tax year subject to examination by state taxing authorities under applicable statutes of limitations is 2014. In July 2020, Minnesota began an audit of tax years 2015 - 2018. As of Dec. 31, 2021, 0 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, 2021		Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions	$	23	$	21
Unrecognized tax benefit — Temporary tax positions	3		3
Total unrecognized tax benefit	$	26	$	24

Changes in unrecognized tax benefits:

(Millions of Dollars)	2021		2020		2019
Balance at Jan. 1	$	24	$	20	$	17
Additions based on tax positions related to the current year	2		2		3
Reductions based on tax positions related to the current year	—		—		(1)
Additions for tax positions of prior years	—		16		1
Reductions for tax positions of prior years	—		(14)		—
Balance at Dec. 31	$	26	$	24	$	20

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
NOL and tax credit carryforwards	$	(13)	$	(11)

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 $14 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.

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2021		2020		2019
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(2)	$	(2)	$	(1)
Interest expense related to unrecognized tax benefits	—		—		(1)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(2)	$	(2)	$	(2)

NaN 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:

(Millions of Dollars)	2021		2020
Federal NOL carryforward	$	77	$	—
Federal tax credit carryforwards	704		543
State NOL carryforwards	344		151
Valuation allowances for state NOL carryforwards	(1)		(1)
State tax credit carryforwards, net of federal detriment (a)	78		71
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(64)		(59)

(a)State tax credit carryforwards are net of federal detriment of $21 million and $19 million as of Dec. 31, 2021 and 2020, respectively.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2021 and 2020, respectively.

Federal carryforward periods expire between 2031 and 2041 and state carryforward periods expire starting 2022.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

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Effective income tax rate for years ended Dec. 31:

	2021		2020		2019
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	7.0		7.0		7.1
Increases (decreases) in tax from:
Wind PTCs	(27.8)		(19.3)		(11.8)
Plant regulatory differences (a)	(8.1)		(7.2)		(7.4)
Other tax credits, net NOL & tax credit allowances	(1.4)		(1.2)		(1.5)
Change in unrecognized tax benefits	0.5		1.0		0.5
NOL Carryback	—		(2.1)		—
Other, net	0.2		(0.2)		0.1
Effective income tax rate	(8.6)	%	(1.0)	%	8.0	%

(a)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions.

Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)	2021		2020		2019
Current federal tax (benefit) expense	$	(10)	$	41	$	80
Current state tax (benefit) expense	(1)		12		8
Current change in unrecognized tax expense (benefit)	1		9		(1)
Deferred federal tax benefit	(87)		(102)		(86)
Deferred state tax expense	49		38		43
Deferred change in unrecognized tax expense (benefit)	2		(3)		4
Deferred ITCs	(2)		(1)		(1)
Total income tax (benefit) expense	$	(48)	$	(6)	$	47

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2021		2020		2019
Deferred tax expense excluding items below	$	109	$	61	97
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(145)		(127)		(135)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other	—		(1)		(1)
Deferred tax benefit	$	(36)	$	(67)	$	(39)

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2021		2020 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,679	$	2,482
Regulatory assets	260		270
Operating lease assets	123		147
Deferred fuel costs	92		7
Pension expense	73		72
Other	13		7
Total deferred tax liabilities	$	3,240	$	2,985
Deferred tax assets:
Tax credit carryforward	$	782	$	614
Regulatory Liabilities	325		349
Operating lease liabilities	123		147
NOL and tax credit valuation allowances	(64)		(59)
Other employee benefits	32		38
NOL carryforward	43		12
Deferred ITCs	5		5
Other	45		39
Total deferred tax assets	$	1,291	$	1,145
Net deferred tax liability	$	1,949	$	1,840

(a)Prior periods have been reclassified to conform to current year presentation.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

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

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

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

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

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion.

Unscheduled distributions from real estate commingled funds’ investments may be redeemed with proper notice, however, may be delayed or discounted as a result of fund illiquidity.

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

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion.

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In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.

Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements of NSP-Minnesota.

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund — The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $1.3 billion and $981 million as of Dec. 31, 2021 and 2020, respectively, and unrealized losses were $7 million and $5 million as of Dec. 31, 2021 and 2020, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

	Dec. 31, 2021
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	64	$	64	$	—	$	—	$	—	$	64
Commingled funds	856		—		—		—		1,294		1,294
Debt securities	631		—		666		9		—		675
Equity securities	411		1,222		1		—		—		1,223
Total	$	1,962	$	1,286	$	667	$	9	$	1,294	$	3,256

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.

	Dec. 31, 2020
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	40	$	40	$	—	$	—	$	—	$	40
Commingled funds	787		—		—		—		1,041		1,041
Debt securities	528		—		572		13		—		585
Equity securities	446		1,109		2		—		—		1,111
Total	$	1,801	$	1,149	$	574	$	13	$	1,041	$	2,777

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2021 and 2020, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2021:

	Final Contractual Maturity
(Millions of Dollars)	Due in 1 year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	4	$	149	$	208	$	314	$	675

Rabbi Trusts

NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions.

Cost and fair value of assets held in rabbi trusts:

	Dec. 31, 2021
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Mutual funds	$	10	$	13	$	—	$	—	$	13
Total	$	10	$	13	$	—	$	—	$	13

(a)    Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

	Dec. 31, 2020
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	1	$	1	$	—	$	—	$	1
Mutual funds	14		16		—		—		16
Total	$	15	$	17	$	—	$	—	$	17

(a)    Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Derivative Instruments Fair Value Measurements

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

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Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.

As of Dec. 31, 2021, accumulated other comprehensive loss related to settled interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged interest rate transactions impact earnings. As of Dec. 31, 2021, NSP-Minnesota had no unsettled interest rate derivatives.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. NSP-Minnesota is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.

Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives.

As of Dec. 31, 2021, NSP-Minnesota had no commodity contracts designated as cash flow hedges. NSP-Minnesota may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b)	Dec. 31, 2021	Dec. 31, 2020
MWh of electricity	57	65
MMBtu of natural gas	85	83

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets. NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.

As of Dec. 31, 2021, 8 of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $33 million or 63% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $17 million or 34% of this credit exposure, was not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties, comprising an immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2021		2020		2019
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(19)	$	(20)	$	(20)
After-tax net realized losses on derivative transactions reclassified into earnings	2		1		—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(17)	$	(19)	$	(20)

Impact of derivative activity:

	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2021
Other derivative instruments
Electric commodity	$	—	$	3
Natural gas commodity	—		(3)
Total	$	—	$	—
Year Ended Dec. 31, 2020
Other derivative instruments
Electric commodity	$	—	$	2
Natural gas commodity	—		(2)
Total	$	—	$	—
Year Ended Dec. 31, 2019
Other derivative instruments
Electric commodity	$	—	$	2
Natural gas commodity	—		(3)
Total	$	—	$	(1)

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	51	(b)
Electric commodity	—			(3)		(c)	—
Natural gas commodity	—			1		(d)	(6)		(d)
Total	$	—		$	(2)		$	45

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	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(5)	(b)
Electric commodity	—			(3)		(c)	—
Natural gas commodity	—			2		(d)	(4)		(d)
Total	$	—		$	(1)		$	(9)

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:					Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 2019
Other derivative instruments
Electric commodity	$	—	$	1	(c)	$	—
Natural gas commodity	—		1		(d)	(3)		(d)
Total	$	—	$	2		$	(3)

(a)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.

(b)Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate.

(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d)Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 and 2019.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2021 and 2020, there were $3 million and $4 million derivative instruments in a liability position with such underlying contract provisions, respectively.

Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2021 and 2020, there were approximately $48 million and $14 million of derivative instruments in a liability position with such underlying contract provisions, respectively.

Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2021 and 2020.

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Recurring Fair Value Measurements — NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2021												Dec. 31, 2020
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Commodity trading	$	9	$	40	$	22	$	71	$	(53)	$	18	$	1	$	26	$	—	$	27	$	(25)	$	2
Electric commodity	—		—		30		30		(1)		29		—		—		13		13		(1)		12
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative assets	$	9	$	46	$	52	$	107	$	(54)	$	53	$	1	$	29	$	13	$	43	$	(26)	$	17
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	6	$	34	$	35	$	75	$	(42)	$	33	$	7	$	39	$	—	$	46	$	(41)	$	5
Total noncurrent derivative assets	$	6	$	34	$	35	$	75	$	(42)	$	33	$	7	$	39	$	—	$	46	$	(41)	$	5

	Dec. 31, 2021												Dec. 31, 2020
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	13	$	58	$	4	$	75	$	(58)	$	17	$	3	$	18	$	10	$	31	$	(25)	$	6
Electric commodity	—		—		1		1		(1)		—		—		—		1		1		(1)		—
Natural gas commodity	—		4		—		4		—		4		—		2		—		2		—		2
Total current derivative liabilities	$	13	$	62	$	5	$	80	$	(59)	21		$	3	$	20	$	11	$	34	$	(26)	8
PPAs (b)											14												14
Current derivative instruments											$	35											$	22
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	15	$	48	$	26	$	89	$	(53)	$	36	$	2	$	35	$	13	$	50	$	(27)	$	23
Total noncurrent derivative liabilities	$	15	$	48	$	26	$	89	$	(53)	36		$	2	$	35	$	13	$	50	$	(27)	23
PPAs (b)											35												48
Noncurrent derivative instruments											$	71											$	71

(a)NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2021 and 2020. At Dec. 31, 2021 derivative assets and liabilities include 0 obligations to return cash collateral. At Dec. 31, 2020 derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include the rights to reclaim cash collateral of $16 million and $1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2021, 2020 and 2019:

	Year Ended Dec. 31
(Millions of Dollars)	2021		2020		2019
Balance at Jan. 1	$	(11)	$	5	$	14
Purchases	54		28		17
Settlements	(82)		(49)		(28)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)	72		(8)		3
Net gains (losses) recognized as regulatory assets and liabilities	23		13		(1)
Balance at Dec. 31	$	56	$	(11)	$	5

(a)Level 3 losses and gains recognized in earnings are subject to offsetting gains and losses of derivative instruments categorized as levels 1 and 2 in the income statement.

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2021, 2020 and 2019.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2021				2020
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	6,747	$	7,761	$	5,904	$	7,391

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Fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2021 and 2020, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Minnesota, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 1.96, 1.78 and 2.74 percent in 2021, 2020, and 2019, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2021 and 2020 were $43 million and $43 million, respectively, of which $3 million and $4 million was attributable to NSP-Minnesota in 2021 and 2020, respectively. In 2021 and 2020, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $6 million, respectively, of which $1 million was attributable to NSP-Minnesota in 2020 and the cost for 2021 was immaterial.

Xcel Energy, which includes NSP-Minnesota, investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as long-term projected return levels. Xcel Energy and NSP-Minnesota continually review their pension assumptions.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

•Investment returns in 2021 were above the assumed level of 6.60%.

•Investment returns in 2020 were above the assumed level of 7.10%.

•Investment returns in 2019 were above the assumed level of 7.10%.

•In 2022, NSP-Minnesota’s expected investment-return assumption is 6.60%.

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

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:

	Dec. 31, 2021 (a)										Dec. 31, 2020 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	31	$	—	$	—	$	—	$	31	$	52	$	—	$	—	$	—	$	52
Commingled funds	304		—		—		274		578		369		—		—		284		653
Debt securities	—		219		1		—		220		—		167		1		—		168
Equity securities	16		—		—		—		16		20		—		—		—		20
Other	—		1		—		7		8		3		1		—		—		4
Total	$	351	$	220	$	1	$	281	$	853	$	444	$	168	$	1	$	284	$	897

(a)See Note 8 for further information on fair value measurement inputs and methods.

For each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:

	Dec. 31, 2021 (a)										Dec. 31, 2020 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Commingled funds	$	—	$	—	$	—	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Debt securities	—		2		—		—		2		—		2		—		—		2
Total	$	—	$	2	$	—	$	1	$	3	$	—	$	2	$	—	$	—	$	2

(a)See Note 8 for further information on fair value measurement inputs and methods.

NaN assets were transferred in or out of Level 3 for 2021 or 2020.

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Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2020 to Dec. 31, 2021, due primarily to benefit

payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows:

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2021		2020		2021		2020
Change in Benefit Obligation:
Obligation at Jan. 1	$	989	$	942	$	73	$	76
Service cost	30		27		—		—
Interest cost	25		31		2		2
Plan amendments	1		—		—		—
Actuarial (gain) loss	(28)		84		(5)		2
Benefit payments	(140)		(95)		(6)		(7)
Obligation at Dec. 31	$	877	$	989	$	64	$	73
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	897	$	815	$	2	$	3
Actual return on plan assets	62		133		—		—
Employer contributions	34		44		7		6
Benefit payments	(140)		(95)		(6)		(7)
Fair value of plan assets at Dec. 31	$	853	$	897	$	3	$	2
Funded status of plans at Dec. 31	$	(24)	$	(92)	$	(61)	$	(71)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current liabilities	$	—	$	—	$	(3)	$	(5)
Noncurrent liabilities	(24)		(92)		(58)		(66)
Net amounts recognized	$	(24)	$	(92)	$	(61)	$	(71)

    

	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2021		2020		2021		2020
Discount rate for year-end valuation	3.08	%	2.71	%	3.09	%	2.65	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	Pri-2012		Pri-2012		Pri-2012		Pri-2012
Health care costs trend rate — initial: Pre-65	N/A		N/A		5.30	%	5.50	%
Health care costs trend rate — initial: Post-65	N/A		N/A		4.90	%	5.00	%
Ultimate trend assumption — initial: Pre-65	N/A		N/A		4.50	%	4.50	%
Ultimate trend assumption — initial: Post-65	N/A		N/A		4.50	%	4.50	%
Years until ultimate trend is reached	N/A		N/A		4		5

The accumulated benefit obligation for the pension plan was $811 million and $912 million as of Dec. 31, 2021 and 2020, respectively.

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Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2021			2020			2019			2021			2020			2019
Service cost	$	30		$	27		$	25		$	—		$	—		$	—
Interest cost	25			31			37			2			2			3
Expected return on plan assets	(52)			(55)			(54)			—			—			—
Amortization of prior service cost	—			—			—			(3)			(3)			(3)
Amortization of net loss	34			33			30			2			1			2
Settlement charge (a)	35			—			—			—			—			—
Net periodic pension cost	72			36			38			1			—			2
Effects of regulation	(44)			(4)			(5)			—			—			—
Net benefit cost recognized for financial reporting	$	28		$	32		$	33		$	1		$	—		$	2
Significant Assumptions Used to Measure Costs:
Discount rate	2.71		%	3.49		%	4.31		%	2.65		%	3.47		%	4.32		%
Expected average long-term increase in compensation level	3.75			3.75			3.75			—			—			—
Expected average long-term rate of return on assets	6.60			7.10			7.10			4.10			4.50			4.50

(a)A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2021, as a result of lump-sum distributions during the 2021 plan year, NSP-Minnesota recorded a total pension settlement charge of $35 million in 2021, which was not recognized due to the effects of regulation. There were 0 settlement charges recorded to the qualified pension plans in 2020 and 2019.

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2021		2020		2021		2020
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	307	$	414	$	31	$	37
Prior service credit	—		—		(4)		(6)
Total	$	307	$	414	$	27	$	31
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	25	$	29	$	—	$	—
Noncurrent regulatory assets	282		385		25		29
Deferred income taxes	—		—		1		1
Net-of-tax accumulated other comprehensive income	—		—		1		1
Total	$	307	$	414	$	27	$	31
Measurement date	Dec 31, 2021		Dec 31, 2020		Dec 31, 2021		Dec 31, 2020

Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2019 - 2022 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all 4 of Xcel Energy’s pension plans were as follows:

•$50 million in January 2022, of which $5 million is attributable to NSP-Minnesota.

•$131 million in 2021, of which $34 million was attributable to NSP-Minnesota.

•$150 million in 2020, of which $44 million was attributable to NSP-Minnesota.

•$154 million in 2019, of which $47 million was attributable to NSP-Minnesota.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows:

•$9 million in 2022, of which $6 million is attributable to NSP-Minnesota.

•$15 million in 2021, of which $8 million, was attributable to NSP-Minnesota.

•$11 million in 2020, of which $6 million was attributable to NSP-Minnesota.

•$15 million in 2019, of which $8 million was attributable to NSP-Minnesota.

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Target asset allocations:

	Pension Benefits				Postretirement Benefits
	2021		2020		2021		2020
Domestic and international equity securities	33	%	35	%	15	%	15	%
Long-duration fixed income and interest rate swap securities	37		35		—		—
Short-to-intermediate fixed income securities	11		13		71		72
Alternative investments	17		15		8		9
Cash	2		2		6		4
Total	100	%	100	%	100	%	100	%

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year

Plan Amendments — In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022.

In 2020, there were 0 significant plan amendments made which affected the postretirement benefit obligation.

In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.

Projected Benefit Payments

NSP-Minnesota’s projected benefit payments:

(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2022	$	118	$	6	$	—	$	6
2023	72		6		—		6
2024	68		5		—		5
2025	67		5		—		5
2026	64		5		—		5
2027-2031	292		18		—		18

Defined Contribution Plans

Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $12 million in 2021, 2020 and 2019.

Multiemployer Plans

NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

10. Commitments and Contingencies

Legal

NSP-Minnesota 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, 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-Minnesota’s consolidated financial statements. Legal fees are generally expensed as incurred.

Rate Matters and Other

NSP-Minnesota is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

Minnesota Winter Storm Uri Costs — In its Minnesota jurisdiction, NSP-Minnesota is participating in a contested case regarding the prudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses. The OAG recommended the MPUC deny recovery of up to $179 million, the largest recommendation among the intervenor positions.

NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event. An MPUC decision is expected in the summer of 2022.

Sherco — In 2018, NSP-Minnesota and Southern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.

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In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.

In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.

In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate. A final decision by the MPUC is pending. A loss related to this matter is deemed remote.

Westmoreland Arbitration — In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, Southern Minnesota Municipal Power Agency and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards.

NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the first quarter of 2022. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined.

MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.

In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit subsequently vacated and remanded Opinion No. 551.

In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds.

In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint.

In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in ROE for the first complaint period, second complaint period and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.

The MISO TOs and various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. Oral arguments were held in late 2021 and a decision is expected by the end of the third quarter of 2022.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate process.

Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to have sent wastes to that site.

Historical MGP, Landfill and Disposal Sites

NSP-Minnesota is currently investigating, remediating or performing post closure actions at 7 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).

NSP-Minnesota has recognized its best estimate of costs/liabilities from final resolution of these issues; however, the outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, NSP-Minnesota has 3 regulated ash units in operation.

NSP-Minnesota is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. NaN results above the groundwater protection standards in the rule were identified.

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In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. This final rule required NSP-Minnesota to expedite closure plans for 1 impoundment.

In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined impoundment. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.

Closure costs for existing impoundments are included in the calculation of the ARO.

Federal CWA Waters of the U.S. Rule — NSP-Minnesota is monitoring ongoing changes to the definition of Waters of the U.S. under the CWA. Regardless of which definition is applicable in the states in which we operate, NSP-Minnesota does not anticipate that compliance costs will be material.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.

The retirement of units affected by the final ELG rule is subject to regulatory approval. The exact total cost of ELG compliance is therefore uncertain but NSP-Minnesota does not anticipate that compliance costs will be material.

Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Minnesota estimates the likely future cost for complying with impingement and entrainment requirements is approximately $36 million, to be incurred between 2022 and 2028. NSP-Minnesota believes 6 plants could be required to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $188 million. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes best available retrofit technology and reasonable further progress. The regional haze first planning period requirements were approved by the EPA and implemented by 2014.

All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to NSP-Minnesota facilities are expected to be minimal.

AROs — AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $3.3 billion and $2.8 billion for 2021 and 2020, respectively.

NSP-Minnesota’s AROs were as follows:

	2021
(Millions  of Dollars)	Jan. 1, 2021		Amounts Incurred (a)		Accretion		Cash Flow Revisions (b)		Dec. 31, 2021 (c)
Electric
Nuclear	$	1,957	$	—	$	99	$	—	$	2,056
Wind	270		101		13		—		384
Steam and other production	67		6		2		(2)		73
Distribution	16		—		—		—		16
Natural gas
Transmission and distribution	39		—		2		14		55
Common
Miscellaneous	1		—		—		—		1
Total liability	$	2,350	$	107	$	116	$	12	$	2,585

(a)Amounts incurred relate to the wind farms placed in service in 2021 (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset.

(b)In 2021, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.

(c)There were no ARO amounts settled in 2021.

	2020
(Millions  of Dollars)	Jan. 1, 2020		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Cash Flow Revisions (c)		Dec. 31, 2020
Electric
Nuclear	$	2,068	$	—	$	—	$	105	$	(216)	$	1,957
Wind	113		90		—		7		60		270
Steam and other production	47		—		(3)		2		21		67
Distribution	15		—		—		1		—		16
Miscellaneous	—		—		—		—		—		—
Natural gas
Transmission and distribution	36		—		—		2		1		39
Common
Miscellaneous	1		—		—		—		—		1
Total liability	$	2,280	$	90	$	(3)	$	117	$	(134)	$	2,350

(a)Amounts incurred relate to the wind farms placed in service in 2020 (Blazing Star 1, Crowned Ridge, Jeffers and Community Wind North).

(b)Amounts settled related to closure of certain ash containment facilities.

(c)In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities.

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2021. Therefore, an ARO has not been recorded for these facilities.

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Nuclear Related

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.5 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.0 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.

NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its 3 reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 billion for each of NSP-Minnesota’s 2 nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.

All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of $11 million for business interruption insurance and $33 million for property damage insurance if losses exceed accumulated reserve funds.

Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 47 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension. NSP-Minnesota expects a decision by year-end 2023.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.

Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.

Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.

NSP-Minnesota had $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2021. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO.

	Regulatory Basis
(Millions of Dollars)	2021		2020
Estimated decommissioning cost obligation from most recently      approved study (in 2014 dollars)	$	3,012	$	3,012
Effect of escalating costs	1,006		844
Estimated decommissioning cost obligation (in current dollars)	4,018		3,856
Effect of escalating costs to payment date	7,187		7,349
Estimated future decommissioning costs (undiscounted)	11,205		11,205
Effect of discounting obligation (using average risk-free interest     rate of 1.96% and 1.64% for 2021 and 2020, respectively)	(4,651)		(4,181)
Discounted decommissioning cost obligation	$	6,554	$	7,024
Assets held in external decommissioning trust	$	3,256	$	2,777
Underfunding of external decommissioning fund compared to      the discounted decommissioning obligation	3,298		4,247

Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.

Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)	2021		2020
Discounted decommissioning cost obligation - regulated basis	$	6,554	$	7,024
Differences in discount rate and market risk premium	(2,209)		(2,628)
O&M costs not included for GAAP	(1,584)		(1,734)
ARO differences between 2020 and 2014 cost studies	(705)		(705)
Nuclear production decommissioning ARO - GAAP	$	2,056	$	1,957

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)	2021		2020		2019
Annual decommissioning recorded as depreciation expense: (a) (b)	$	22	$	20	$	20

(a)Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

(b)Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.

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The 2017 nuclear decommissioning filing, effective Jan. 1, 2019, has been approved by the MPUC. In March 2020, the MPUC approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. In December 2020, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2022. Also, as of December 2020, NSP-Minnesota submitted a Petition for approval of the 2022 - 2024 Nuclear Decommissioning Study and Assumptions. Contemplated but not proposed in this filing, was the 10-year extension of the license to operate the Monticello Plant, moving the planned retirement date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan Supplement does include a 10-year extension of the license. On Feb. 8, 2022, the MPUC ruled on and approved the 10-year extension for the Monticello nuclear facility.

Leases

NSP-Minnesota evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent NSP-Minnesota's rights to use leased assets. The present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted average of 3.8%).

NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
PPAs	$	556	$	558
Other	74		74
Gross operating lease ROU assets	630		632
Accumulated amortization	(222)		(144)
Net operating lease ROU assets	$	408	$	488

Components of lease expense:

(Millions of Dollars)	2021		2020		2019
Operating leases
PPA capacity payments	$	96	$	89	$	76
Other operating leases (a)	8		8		9
Total operating lease expense (b)	$	104	$	97	$	85

(a)Includes short-term lease expense of $2 million, $2 million and $1 million for 2021, 2020 and 2019, respectively.

(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

Commitments under operating leases as of Dec. 31, 2021:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases
2022	$	96	$	9	$	105
2023	98		12		110
2024	100		7		107
2025	80		7		87
2026	40		7		47
Thereafter	—		31		31
Total minimum obligation	414		73		487
Interest component of obligation	(32)		(12)		(44)
Present value of minimum obligation	$	382	$	61	443
Less current portion					(90)
Noncurrent operating lease liabilities					$	353
Weighted-average remaining lease term in years					8.5

(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

(b)PPA operating leases contractually expire at various dates through 2039.

PPAs and Fuel Contracts

Non-Lease PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2033, contain minimum energy purchase commitments. Total energy payments on those contracts were $149 million, $112 million and $102 million in 2021, 2020 and 2019, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $55 million, $52 million and $54 million in 2021, 2020 and 2019, respectively.

Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.

At Dec. 31, 2021, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity		Energy (a)
2022	$	60	$	165
2023	61		169
2024	63		174
2025	26		53
2026	9		10
Thereafter	10		38
Total (b)	$	229	$	609

(a)Excludes contingent energy payments for renewable energy PPAs.

(b)Includes amounts allocated to NSP-Wisconsin through intercompany charges.

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Fuel Contracts — NSP-Minnesota has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2022 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases for these contracts as of Dec. 31, 2021:

(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2022	$	219	$	89	$	95	$	128
2023	79		109		—		114
2024	48		82		—		108
2025	1		119		—		98
2026	1		29		—		97
Thereafter	1		309		—		107
Total (a)	$	349	$	737	$	95	$	652

(a)Includes amounts allocated to NSP-Wisconsin through intercompany charges.

VIEs

Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity. NSP-Minnesota evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.

NSP-Minnesota concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. NSP-Minnesota had approximately 1,347 MW of capacity under long-term PPAs at both Dec. 31, 2021 and 2020 with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:

	2021
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	$	(19)		$	(3)	$	(22)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives, net of tax of $—	2		(a)	—		2
Net current period other comprehensive income	2			—		2
Accumulated other comprehensive loss at Dec. 31	$	(17)		$	(3)	$	(20)

(a)Included in interest charges.

	2020
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	$	(20)		$	(3)	$	(23)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives, net of tax of $—	1		(a)	—		1
Net current period other comprehensive income	1			—		1
Accumulated other comprehensive loss at Dec. 31	$	(19)		$	(3)	$	(22)

(a)Included in interest charges.

12. Segment Information

NSP-Minnesota evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

NSP-Minnesota has the following reportable segments:

•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.

NSP-Minnesota also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments. As an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

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NSP-Minnesota’s segment information:

(Millions of Dollars)	2021		2020		2019
Regulated Electric
Operating revenues — external (a)	$	5,094	$	4,571	$	4,506
Intersegment revenue	1		1		1
Total revenues	$	5,095	$	4,572	$	4,507
Depreciation and amortization	869		773		742
Interest charges and financing costs	240		221		205
Income tax (benefit) expense	(53)		(14)		36
Net income	566		553		491
Regulated Natural Gas
Operating revenues — external (b)	$	623	$	493	$	571
Intersegment revenue	1		—		1
Total revenues	$	624	$	493	$	572
Depreciation and amortization	56		51		49
Interest charges and financing costs	18		17		16
Income tax expense	6		7		12
Net income	29		30		40
All Other
Total revenues	$	39	$	37	$	35
Depreciation and amortization	1		1		—
Income tax (benefit) expense	(1)		1		(1)
Net income	11		8		12
Consolidated Total
Total revenues (a)(b)	$	5,758	$	5,102	$	5,114
Reconciling eliminations	(2)		(1)		(2)
Total operating revenues	$	5,756	$	5,101	$	5,112
Depreciation and amortization	926		825		791
Interest charges and financing costs	258		238		221
Income tax (benefit) expense	(48)		(6)		47
Net income	606		591		543

(a)    Operating revenues include $501 million, $440 million and $457 million of affiliate electric revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.

(b)    Operating revenues include $1 million of affiliate gas revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.

13. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.

See Note 5 for further information.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:

(Millions of Dollars)	2021		2020		2019
Operating revenues:
Electric	$	501	$	440	$	457
Gas	1		1		1
Operating expenses:
Purchased power	67		59		61
Transmission expense	121		109		116
Other operating expenses — paid to Xcel Energy Services Inc.	615		584		533
Interest expense	—		—		1

Accounts receivable and payable with affiliates at Dec. 31:

	2021				2020
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	13	$	—	$	6	$	—
PSCo	16		—		1		—
SPS	—		2		—		3
Other subsidiaries of Xcel Energy Inc.	—		61		25		63
	$	29	$	63	$	32	$	66

ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.

In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2021, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in NSP-Minnesota’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2021 that materially affected, or are reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Minnesota has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.

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During the year and in preparation for issuing its report for the year ended Dec. 31, 2021 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in NSP-Minnesota’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.

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

ITEM 9B — OTHER INFORMATION

None.

ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

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

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11 — EXECUTIVE COMPENSATION

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated by reference.

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is contained in Xcel Energy Inc.’s Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated by reference.

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PART IV

ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES

1	Consolidated Financial Statements:
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2021.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
	Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
	Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
	Consolidated Balance Sheets — As of Dec. 31, 2021 and 2020.
	Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
2	Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2021, 2020 and 2019.
3	Exhibits
*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	3.01
3.02*	By-Laws of NSP-Minnesota as Amended and Restated on Jan. 25, 2019	NSP-Minnesota Form 10-K for the year ended Dec. 31, 2018	3.02
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures between NSP-Minnesota and said Trustee	Xcel Energy Inc. Form S-3 dated April 18, 2018	4(b)(3)
4.02*	Supplemental Trust Indenture dated June 1, 1995, creating $250 million principal amount of 7.125% First Mortgage Bonds, Series due July 1, 2025	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017	4.11
4.03*	Supplemental Trust Indenture dated March 1, 1998, creating $150 million principal amount of 6.5% First Mortgage Bonds, Series due March 1, 2028	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017	4.12
4.04*	Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	4.51
4.05*	Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities	Xcel Energy Inc. Form S-3 dated April 18, 2018	4(b)(7)
4.06*	Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee (Assignment and Assumption of Indenture)	NSP-Minnesota Form 10-12G dated Oct. 5, 2000	4.63
4.07*	Supplemental Trust Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $200 million principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035	NSP-Minnesota Form 8-K dated July 14, 2005	4.01
4.08*	Supplemental Trust Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400 million principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036	NSP-Minnesota Form 8-K dated May 18, 2006	4.01
4.09*	Supplemental Trust Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee	NSP-Minnesota Form 8-K dated June 19, 2007	4.01
4.10*	Supplemental Trust Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300 million principal amount of 5.35% First Mortgage Bonds, Series due Nov. 1, 2039	NSP-Minnesota Form 8-K dated Nov. 16, 2009	4.01
4.11*	Supplemental Trust Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal of 1.950% First Mortgage Bonds, Series due Aug. 15, 2015 and $250 million principal amount of 4.850% First Mortgage Bonds, Series due Aug. 15, 2040	NSP-Minnesota Form 8-K dated Aug. 4, 2010	4.01
4.12*	Supplemental Trust Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $300 million principal amount of 2.15% First Mortgage Bonds, Series due Aug. 15, 2022 and $500 million principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042	NSP-Minnesota Form 8-K dated Aug. 13, 2012	4.01
4.13*	Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60% First Mortgage Bonds, Series due May 15, 2023	NSP-Minnesota Form 8-K dated May 20, 2013	4.01
4.14*	Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125% First Mortgage Bonds, Series due May 15, 2044	NSP-Minnesota Form 8-K dated May 13, 2014	4.01
4.15*	Supplemental Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 2.20% First Mortgage Bonds, Series due Aug. 15, 2020 and $300 million principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045	NSP-Minnesota Form 8-K dated Aug. 11, 2015	4.01
4.16*	Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $350 million principal amount of 3.600% First Mortgage Bonds, Series due May 15, 2046	NSP-Minnesota Form 8-K dated May 31, 2016	4.01
4.17*	Supplemental Indenture dated as of Sept. 1, 2017 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 3.60% First Mortgage Bonds, Series due Sept. 15, 2047	NSP-Minnesota Form 8-K dated Sept. 13, 2017	4.01
4.18*	Supplemental Trust Indenture dated as of Sept. 1, 2019 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 2.90% First Mortgage Bonds, Series due March 1, 2050	NSP-Minnesota Form 8-K dated Sept. 10, 2019	4.01

56

4.19*	Supplemental Indenture dated as of June 8, 2020 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700 million principal amount of 2.60% First Mortgage Bonds, Series due June 1, 2051	NSP-Minnesota 8-K dated June 15, 2020	4.01
4.20*	Supplemental Indenture dated as of March 1, 2021 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052	NSP-Minnesota 8-K dated March 30, 2021	4.01
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.05
10.03*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.18
10.04*+	Fifth Amendment to Exhibit 10.02 dated May 3, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016	10.01
10.05*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	10.01
10.06*+	Eighth Amendment to Exhibit 10.02 dated March 31, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020	10.02
10.07*+	Ninth Amendment to Exhibit 10.02 dated May 22, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020	10.01
10.08*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.17
10.09*+	Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	Appendix A
10.10*+	First Amendment to Exhibit 10.09 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	10.01
10.11*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	10.08
10.12*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.07
10.13*+	First Amendment to Exhibit 10.12 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.17
10.14*+	Second Amendment to Exhibit 10.12 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	10.22
10.15*+	Third Amendment to Exhibit 10.12 dated Sept. 30, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016	10.01
10.16*+	Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	10.1
10.17*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.34
10.18*+	Form of Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for Awards of Restricted Stock Units and/or Performance Share Units	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.35
10.19*+	Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for awards since 2020	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019	10.33
10.20*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	Schedule 14A
10.21*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 26, 2015	10.02
10.22*+	Summary of Non-Employee Director Compensation, effective as of Oct. 1, 2021	Xcel Energy Inc. Form 10-Q for the quarter ended September 30, 2021	10.01
10.23*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.36
10.24*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	H-1
10.25*	Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota	NSP-Wisconsin Form S-4 dated Jan. 21, 2004	10.01
10.26*	Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents	Xcel Energy Inc. Form 8-K dated June 7, 2019	99.02
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

57

SCHEDULE II

NSP-Minnesota and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31

	Allowance for bad debts
(Millions of Dollars)	2021		2020		2019
Balance at Jan. 1	$	33	$	23	$	24
Additions charged to costs and expenses	24		24		13
Additions charged to other accounts (a)	5		5		7
Deductions from reserves (b)	(17)		(19)		(21)
Balance at Dec. 31	$	45	$	33	$	23

(a)Recovery of amounts previously written-off.

(b)Deductions related primarily to bad debt write-offs.

ITEM 16 — FORM 10-K SUMMARY

None.

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Signatures

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

	NORTHERN STATES POWER COMPANY (A MINNESOTA CORPORATION)
Feb. 23, 2022	/s/ BRIAN J. VAN ABEL
	Brian J. Van Abel
	Executive Vice President, Chief Financial Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.

/s/ ROBERT C. FRENZEL	/s/ CHRISTOPHER B. CLARK
Robert C. Frenzel	Christopher B. Clark
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ BRIAN J. VAN ABEL	/s/ JEFFREY S. SAVAGE
Brian J. Van Abel	Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director	Senior Vice President, Controller
(Principal Financial Officer)	(Principal Accounting Officer)

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

59