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 year ended December 31, 2021

☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from ______________ to ______________

Commission File Number 1-3548

ALLETE, Inc.

(Exact name of registrant as specified in its charter)

Minnesota	41-0418150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

30 West Superior Street, Duluth, Minnesota 55802-2093

(Address of principal executive offices, including zip code)

(218) 279-5000

(Registrant’s telephone number, including area code)

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

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, without par value	ALE	New York Stock Exchange

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 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 Exchange Act).     Yes ☐     No ☒

The aggregate market value of voting stock held by nonaffiliates on June 30, 2021, was $3,649,980,087.

As of February 1, 2022, there were 53,243,671 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 2022 Annual Meeting of Shareholders are incorporated by reference in Part III.

Index

Definitions		4
Forward-Looking Statements		6
Part I		7
	Item 1. Business	7
	Regulated Operations	9
	Electric Sales / Customers	9
	Seasonality	12
	Power Supply	12
	Transmission and Distribution	14
	Investment in ATC	15
	Properties	15
	Regulatory Matters	15
	Regional Organizations	17
	Minnesota Legislation	17
	Competition	17
	Franchises	18
	ALLETE Clean Energy	18
	U.S. Water Services	19
	Corporate and Other	19
	BNI Energy	19
	Investment in Nobles 2	20
	ALLETE Properties	20
	Non-Rate Base Generation and Miscellaneous	20
	Environmental Matters	21
	Human Capital Management	21
	Availability of Information	22
	Information about our Executive Officers	23
	Item 1A. Risk Factors	24
	Item 1B. Unresolved Staff Comments	34
	Item 2. Properties	34
	Item 3. Legal Proceedings	34
	Item 4. Mine Safety Disclosures	34
Part II		35
	Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
	Item 6. [Reserved]	36
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
	Overview	36
	2021 Compared to 2020	38
	Critical Accounting Policies	41
	Outlook	43
	Liquidity and Capital Resources	51
	Capital Requirements	54
	Environmental and Other Matters	54
	Market Risk	55
	Recently Adopted Accounting Standards	55
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk	56
	Item 8. Financial Statements and Supplementary Data	56

ALLETE, Inc. 2021 Form 10-K

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Index (Continued)

	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	56
	Item 9A. Controls and Procedures	56
	Item 9B. Other Information	56
	Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	56
Part III		57
	Item 10. Directors, Executive Officers and Corporate Governance	57
	Item 11. Executive Compensation	57
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	58
	Item 13. Certain Relationships and Related Transactions, and Director Independence	58
	Item 14. Principal Accountant Fees and Services	59
Part IV		59
	Item 15. Exhibits and Financial Statement Schedules	59
	Item 16. Form 10-K Summary	63
Signatures		64
Report of Independent Registered Public Accounting Firm		66
Consolidated Financial Statements - Audited		68
	Consolidated Balance Sheet	68
	Consolidated Statement of Income	69
	Consolidated Statement of Comprehensive Income	70
	Consolidated Statement of Cash Flows	71
	Consolidated Statement of Equity	72
	Notes to Consolidated Financial Statements	73
	Note 1. Operations and Significant Accounting Policies	73
	Note 2. Property, Plant and Equipment	84
	Note 3. Jointly-Owned Facilities and Assets	85
	Note 4. Regulatory Matters	86
	Note 5. Equity Investments	91
	Note 6. Fair Value	92
	Note 7. Short-Term and Long-Term Debt	94
	Note 8. Commitments, Guarantees and Contingencies	97
	Note 9. Common Stock and Earnings Per Share	104
	Note 10. Income Tax Expense	105
	Note 11. Pension and Other Postretirement Benefit Plans	108
	Note 12. Employee Stock and Incentive Plans	117
	Note 13. Business Segments	119
	Note 14. Quarterly Financial Data (Unaudited)	122
Schedule II		122

ALLETE, Inc. 2021 Form 10-K

3

Definitions

The following abbreviations or acronyms are used in the text. References in this report to “we,” “us” and “our” are to ALLETE, Inc. and its subsidiaries, collectively.

Abbreviation or Acronym	Term
AFUDC	Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
ALLETE	ALLETE, Inc.
ALLETE Clean Energy	ALLETE Clean Energy, Inc. and its subsidiaries
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
ALLETE South Wind	ALLETE South Wind, LLC
ALLETE Transmission Holdings	ALLETE Transmission Holdings, Inc.
ArcelorMittal	ArcelorMittal USA LLC
ATC	American Transmission Company LLC
Basin	Basin Electric Power Cooperative
Bison	Bison Wind Energy Center
BNI Energy	BNI Energy, Inc. and its subsidiary
Boswell	Boswell Energy Center
Camp Ripley	Camp Ripley Solar Array
CIP	Conservation Improvement Program
Cliffs	Cleveland-Cliffs Inc.
Company	ALLETE, Inc. and its subsidiaries
COVID-19	2019 novel coronavirus
DC	Direct Current
EIS	Environmental Impact Statement
EPA	United States Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
FERC	Federal Energy Regulatory Commission
Form 8-K	ALLETE Current Report on Form 8-K
Form 10-K	ALLETE Annual Report on Form 10-K
Form 10-Q	ALLETE Quarterly Report on Form 10-Q
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gases
GNTL	Great Northern Transmission Line
Hibbing Taconite	Hibbing Taconite Co.
Husky Energy	Husky Energy Inc.
Invest Direct	ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
IRP	Integrated Resource Plan
Item ___	Item ___ of this Form 10-K
kV	Kilovolt(s)
kW / kWh	Kilowatt(s) / Kilowatt-hour(s)
Lampert Capital Markets	Lampert Capital Markets, Inc.
Laskin	Laskin Energy Center
Manitoba Hydro	Manitoba Hydro-Electric Board
MBtu	Million British thermal units

ALLETE, Inc. 2021 Form 10-K

4

Definitions (continued)

Abbreviation or Acronym	Term
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission
MW / MWh	Megawatt(s) / Megawatt-hour(s)
NAAQS	National Ambient Air Quality Standards
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
Nobles 2	Nobles 2 Power Partners, LLC
NOL	Net Operating Loss
NOX	Nitrogen Oxides
Northshore Mining	Northshore Mining Company, a wholly-owned subsidiary of Cliffs
Note ___	Note ___ to the consolidated financial statements in this Form 10-K
NPDES	National Pollutant Discharge Elimination System
NTEC	Nemadji Trail Energy Center
NYSE	New York Stock Exchange
Oliver Wind I	Oliver Wind I Energy Center
Oliver Wind II	Oliver Wind II Energy Center
PolyMet	PolyMet Mining Corp.
PPA / PSA	Power Purchase Agreement / Power Sales Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCW	Public Service Commission of Wisconsin
RSOP	Retirement Savings and Stock Ownership Plan
SEC	Securities and Exchange Commission
S&P	S&P Global Ratings
Silver Bay Power	Silver Bay Power Company, a wholly-owned subsidiary of Cliffs
SO2	Sulfur Dioxide
South Shore Energy	South Shore Energy, LLC
Square Butte	Square Butte Electric Cooperative, a North Dakota cooperative corporation
SWL&P	Superior Water, Light and Power Company
Taconite Harbor	Taconite Harbor Energy Center
Taconite Ridge	Taconite Ridge Energy Center
Town Center District	Town Center at Palm Coast Community Development District in Florida
United Taconite	United Taconite LLC, a wholly-owned subsidiary of Cliffs
UPM Blandin	UPM, Blandin paper mill owned by UPM-Kymmene Corporation
U.S.	United States of America
U.S. Water Services	U.S. Water Services, Inc. and its subsidiaries
USS Corporation	United States Steel Corporation
WTG	Wind Turbine Generator

ALLETE, Inc. 2021 Form 10-K

5

Forward-Looking Statements

Statements in this report that are not statements of historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there can be no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies (often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “projects,” “likely,” “will continue,” “could,” “may,” “potential,” “target,” “outlook” or words of similar meaning) are not statements of historical facts and may be forward-looking.

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of ALLETE in this Form 10-K, in presentations, on our website, in response to questions or otherwise. These statements are qualified in their entirety by reference to, and are accompanied by, the following important factors, in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements:

•our ability to successfully implement our strategic objectives;

•global and domestic economic conditions affecting us or our customers;

•changes in and compliance with laws and regulations;

•changes in tax rates or policies or in rates of inflation;

•the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;

•weather conditions, natural disasters and pandemic diseases, including the ongoing COVID-19 pandemic;

•our ability to access capital markets, bank financing and other financing sources;

•changes in interest rates and the performance of the financial markets;

•project delays or changes in project costs;

•changes in operating expenses and capital expenditures and our ability to raise revenues from our customers;

•the impacts of commodity prices on ALLETE and our customers;

•our ability to attract and retain qualified, skilled and experienced personnel;

•effects of emerging technology;

•war, acts of terrorism and cybersecurity attacks;

•our ability to manage expansion and integrate acquisitions;

•population growth rates and demographic patterns;

•wholesale power market conditions;

•federal and state regulatory and legislative actions that impact regulated utility economics, including our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities and utility infrastructure, recovery of purchased power, capital investments and other expenses, including present or prospective environmental matters;

•effects of competition, including competition for retail and wholesale customers;

•effects of restructuring initiatives in the electric industry;

•the impacts on our businesses of climate change and future regulation to restrict the emissions of GHG;

•effects of increased deployment of distributed low-carbon electricity generation resources;

•the impacts of laws and regulations related to renewable and distributed generation;

•pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;

•our current and potential industrial and municipal customers’ ability to execute announced expansion plans;

•real estate market conditions where our legacy Florida real estate investment is located may deteriorate; and

•the success of efforts to realize value from, invest in, and develop new opportunities.

Additional disclosures regarding factors that could cause our results or performance to differ from those anticipated by this report are discussed in Part 1, Item 1A under the heading “Risk Factors” of this Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward‑looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the businesses of ALLETE or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by ALLETE in this Form 10-K and in other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect ALLETE’s business.

ALLETE, Inc. 2021 Form 10-K

6

Part I

Item 1. Business

Overview.

ALLETE is a leader in the nation’s clean-energy transformation. Our businesses and dedicated employees deliver sustainable energy solutions that mitigate climate change, build thriving communities, help customers reach their sustainability goals and drive value for shareholders. ALLETE’s largest business, Minnesota Power, recently reached a milestone of providing 50 percent renewable energy, and envisions delivering 100 percent carbon-free energy to customers by 2050—a vision grounded in a steadfast commitment to climate, customers and community through its EnergyForward strategy. ALLETE Clean Energy, our second-largest business, is positioned at the heart of society’s clean-energy transformation and owns, operates and is developing more than 1,300 megawatts of wind energy generation across eight states – helping some of the largest companies in the country reduce their carbon footprint.

In February 2021, Minnesota Power filed its latest IRP with the MPUC, which outlines its clean-energy transition plans through 2035. These plans include expanding its renewable energy supply to 70 percent by 2030, achieving coal-free operations at its facilities by 2035, and investing in a resilient and flexible transmission and distribution grid. Minnesota Power has also set a target to achieve an 80 percent reduction in carbon emissions by 2035 compared to 2005 levels. As part of these plans, Minnesota Power anticipates adding approximately 400 MW of new wind and solar energy resources, retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Minnesota Power’s plans recognize that advances in technology will play a significant role in completing its transition to carbon-free energy supply, reliably and affordably. A final decision on the IRP is expected in second half of 2022.

In recent years, Minnesota Power has transformed its energy supply from more than a 95 percent reliance on coal to become a leader in the nation’s clean-energy transformation. Since 2013, the company has closed or converted seven of its nine coal-fired units and added nearly 900 megawatts of renewable energy sources. Additionally, Minnesota Power has been a leader in energy conservation, surpassing the state’s conservation goals each year for the past decade.

ALLETE is also committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses, and sustains growth. ALLETE is predominately a regulated utility through Minnesota Power, SWL&P, and an investment in ATC. ALLETE’s strategy is to remain predominately a regulated utility while also investing in ALLETE Clean Energy and our Corporate and Other businesses to complement its regulated businesses, balance exposure to the utility’s industrial customers, and provide potential long-term earnings growth.

The ongoing COVID-19 pandemic has resulted in widespread impacts on the global economy and on our employees, customers, contractors, and suppliers. There is considerable uncertainty regarding the length of time for which COVID-19 will continue, if new variants will emerge or the extent and duration of measures to try to contain the virus. Additional disclosures in this Form 10-K regarding the impacts of the ongoing COVID-19 pandemic are located in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 150,000 retail customers. Minnesota Power also has 15 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 4. Regulatory Matters.)

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in seven states, more than 1,300 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 200 MW of wind energy facilities under contract to be sold to others. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

ALLETE, Inc. 2021 Form 10-K

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Overview (Continued)

U.S. Water Services provided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. In 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd.

Corporate and Other is comprised of BNI Energy, our coal mining operations in North Dakota; our investment in Nobles 2, an entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota; South Shore Energy, our non-rate regulated, Wisconsin subsidiary developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility; ALLETE Properties, our legacy Florida real estate investment; other business development and corporate expenditures; unallocated interest expense; a small amount of non-rate base generation; approximately 4,000 acres of land in Minnesota; and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2021, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Year Ended December 31	2021		2020		2019
Consolidated Operating Revenue – Millions (a)	$1,419.2		$1,169.1		$1,240.5
Percentage of Consolidated Operating Revenue
Regulated Operations	87	%	84	%	84	%
ALLETE Clean Energy	6	%	7	%	5	%
U.S. Water Services (a)	—		—		3	%
Corporate and Other	7	%	9	%	8	%
	100	%	100	%	100	%

(a)    ALLETE sold U.S. Water Services in the first quarter of 2019.

For a detailed discussion of results of operations and trends, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. For business segment information, see Note 1. Operations and Significant Accounting Policies and Note 13. Business Segments.

ALLETE, Inc. 2021 Form 10-K

8

REGULATED OPERATIONS

Electric Sales / Customers

Regulated Utility Kilowatt-hours Sold
Year Ended December 31	2021	%	2020	%	2019	%
Millions
Retail and Municipal
Residential	1,135	7	1,134	9	1,130	8
Commercial	1,359	9	1,306	10	1,390	10
Industrial	7,196	47	6,192	47	7,277	54
Municipal	590	4	584	4	672	5
Total Retail and Municipal	10,280	67	9,216	70	10,469	77
Other Power Suppliers	5,102	33	4,039	30	3,185	23
Total Regulated Utility Kilowatt-hours Sold	15,382	100	13,255	100	13,654	100

Industrial Customers. In 2021, industrial customers represented 47 percent of total regulated utility kWh sales. Our industrial customers are primarily in the taconite mining, paper, pulp and secondary wood products, and pipeline industries.

The ongoing COVID-19 pandemic and related governmental responses has led to a disruption of economic activity, and could result in an extended disruption of economic activity. This disruption resulted in reduced sales and revenue from industrial customers in 2020 as many industrial customers operated at reduced levels or were temporarily closed or idled during 2020. Sales to our industrial customers in 2021 were similar to levels prior to the COVID-19 pandemic; however, further disruption of economic activity or an extended disruption of economic activity may lead to additional adverse impacts on our industrial customers including reduced production or the temporary idling or indefinite shutdown of facilities, which would result in lower sales and revenue from these customers.

Industrial Customer Kilowatt-hours Sold
Year Ended December 31	2021	%	2020	%	2019	%
Millions
Taconite	5,281	73	4,296	69	5,039	69
Paper, Pulp and Secondary Wood Products	702	10	752	12	1,014	14
Pipelines and Other Industrial	1,213	17	1,144	19	1,224	17
Total Industrial Customer Kilowatt-hours Sold	7,196	100	6,192	100	7,277	100

Six taconite facilities served by Minnesota Power made up approximately 80 percent of 2020 iron ore pellet production in the U.S. according to data from the Minnesota Department of Revenue 2021 Mining Tax Guide. These taconite facilities were owned by Cliffs and USS Corporation at the end of the 2021. (See Large Power Customer Contracts.) Sales to taconite customers represented 5,281 million kWh, or 73 percent of total industrial customer kWh sales in 2021. Taconite, an iron‑bearing rock of relatively low iron content, is abundantly available in northern Minnesota and an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the iron-bearing rock, and agglomerate and pelletize the iron particles into taconite pellets.

Minnesota Power’s taconite customers are capable of producing approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry, which continue to lead the world in environmental performance among steelmaking countries. According to the U.S. Department of Energy, steel production in the U.S. is the most energy efficient of any major steel producing country. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, tubular applications for all industries, and in the construction industry. Steel is also a critical component of the clean energy transformation underway today. The demand for more renewable energy and the need for additional infrastructure to transport green energy from the point of generation to the end user both require steel. Historically, less than 10 percent of Minnesota taconite production has been exported outside of North America.

ALLETE, Inc. 2021 Form 10-K

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REGULATED OPERATIONS (Continued)

Industrial Customers (Continued)

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 82 percent of capacity in 2021 (68 percent in 2020 and 80 percent in 2019). The World Steel Association, an association of steel producers, national and regional steel industry associations, and steel research institutes representing approximately 85 percent of world steel production, projected U.S. steel consumption in 2022 will increase by approximately 6 percent compared to 2021.

The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years:

Minnesota Power Taconite Customer Production
Year	Tons (Millions)
2021*	39
2020	30
2019	37
2018	39
2017	38
2016	28
2015	31
2014	39
2013	37
2012	39
Source: Minnesota Department of Revenue 2021 Mining Tax Guide for years 2012 - 2020.
* Preliminary data from the Minnesota Department of Revenue.

Minnesota Power’s taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in Minnesota Power’s taconite customers’ production would impact our annual earnings per share by approximately $0.04, net of expected power marketing sales at current prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Minnesota Power proactively sells power in the wholesale power markets that is temporarily not required by industrial customers to optimize the value of its generating facilities. Long-term reductions in taconite production or a permanent shut down of a taconite customer may lead Minnesota Power to file a general rate case to recover lost revenue.

In addition to serving the taconite industry, Minnesota Power serves a number of customers in the paper, pulp and secondary wood products industry, which represented 702 million kWh, or 10 percent of total industrial customer kWh sales in 2021. Minnesota Power also has an agreement to provide steam for one paper and pulp customer for use in the customer’s operations. The four major paper and pulp mills we serve reported operating at lower levels in 2021 compared to 2020. Verso Corporation indefinitely idled its paper mill in Duluth, Minnesota, which it subsequently sold to ST Paper in May 2021. (See Outlook – Regulated Operations – Industrial Customers and Prospective Additional Load – Paper, Pulp and Secondary Wood Products – Verso Corporation and ST Paper.)

Large Power Customer Contracts. Minnesota Power had eight Large Power Customer contracts as of December 31, 2021, each serving requirements of 10 MW or more of customer load; however, Minnesota Power and Verso Corporation mutually agreed to resolve the outstanding commitments under the contract in January 2022. The customers as of December 31, 2021 consisted of six taconite facilities owned by Cliffs and USS Corporation as well as four paper and pulp mills. Certain facilities with common ownership are served under combined contracts.

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REGULATED OPERATIONS (Continued)

Large Power Customer Contracts (Continued)

Large Power Customer contracts require Minnesota Power to have a certain amount of generating capacity available. In turn, each Large Power Customer is required to pay a minimum monthly demand charge that covers the fixed costs associated with having this capacity available to serve the customer, including a return on common equity. Most contracts allow customers to establish the level of megawatts subject to a demand charge on a three to four-month basis and require that a portion of their megawatt needs be committed on a take-or-pay basis for at least a portion of the term of the agreement. In addition to the demand charge, each Large Power Customer is billed an energy charge for each kWh used that recovers the variable costs incurred in generating electricity. Five of the Large Power Customer contracts have interruptible service which provides a discounted demand rate in exchange for the ability to interrupt the customers during system emergencies. Minnesota Power also provides incremental production service for customer demand levels above the contractual take-or-pay levels. There is no demand charge for this service and energy is priced at an increment above Minnesota Power’s cost. Incremental production service is interruptible.

All contracts with Large Power Customers continue past the contract termination date unless the required advance notice of cancellation has been given. The required advance notice of cancellation varies from two to four years. Such contracts reduce the impact on earnings that otherwise would result from significant reductions in kWh sales to such customers. Large Power Customers are required to take all of their purchased electric service requirements from Minnesota Power for the duration of their contracts. The rates and corresponding revenue associated with capacity and energy provided under these contracts are subject to change through the same regulatory process governing all retail electric rates. (See Regulatory Matters – Electric Rates.)

Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates. These customers receive estimated bills or make weekly prepayments based on Minnesota Power’s estimate of the customer’s energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite‑producing Large Power Customers have generally predictable energy usage on a week-to-week basis and any differences that occur are trued-up the following month.

Contract Status for Minnesota Power Large Power Customers

As of December 31, 2021

Customer	Industry	Location	Ownership	Earliest Termination Date
Cliffs – Minorca Mine (a)	Taconite	Virginia, MN	Cliffs	December 31, 2025
Hibbing Taconite (a)	Taconite	Hibbing, MN	85.3% Cliffs 14.7% USS Corporation	December 31, 2025
United Taconite and Northshore Mining	Taconite	Eveleth, MN and Babbitt, MN	Cliffs	December 31, 2026
USS Corporation (USS – Minnesota Ore) (a)(b)	Taconite	Mtn. Iron, MN and Keewatin, MN	USS Corporation	December 31, 2025
Boise, Inc. (a)	Paper	International Falls, MN	Packaging Corporation of America	December 31, 2025
UPM Blandin	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	December 31, 2029
Verso Duluth Mill (c)	Paper and Pulp	Duluth, MN	Verso Corporation	(c)
Sappi Cloquet LLC (a)	Paper and Pulp	Cloquet, MN	Sappi Limited	December 31, 2025

(a)The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is December 31, 2025.

(b)USS Corporation owns both the Minntac Plant in Mountain Iron, MN, and the Keewatin Taconite Plant in Keewatin, MN.

(c)On January 29, 2021, Verso Corporation provided notice of termination for its contract. Minnesota Power and Verso Corporation mutually agreed to resolve the outstanding commitments under the contract in January 2022. (See Outlook – Regulated Operations – Industrial Customers and Prospective Additional Load – Paper, Pulp and Secondary Wood Products – Verso Corporation and ST Paper.)

ALLETE, Inc. 2021 Form 10-K

11

REGULATED OPERATIONS (Continued)

Residential and Commercial Customers. In 2021, residential and commercial customers represented 16 percent of total regulated utility kWh sales.

Municipal Customers. In 2021, municipal customers represented 4 percent of total regulated utility kWh sales.

Minnesota Power’s wholesale electric contracts with 15 non-affiliated municipal customers in Minnesota have termination dates ranging from 2024 through 2037, with a majority of contracts effective through 2029. Two of the wholesale contracts include a termination clause requiring a three-year notice to terminate. (See Note 4. Regulatory Matters.)

Other Power Suppliers. The Company also enters into off-system sales with Other Power Suppliers. These sales are at market‑based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

Our PSAs are detailed in Note 8. Commitments, Guarantees and Contingencies, with additional disclosure provided in the following paragraphs.

Basin PSAs. Minnesota Power had an agreement to sell 100 MW of capacity and energy to Basin for a ten-year period which expired in April 2020. Minnesota Power has two additional agreements to sell capacity to Basin at fixed prices. (See Note 8. Commitments, Guarantees and Contingencies.)

Minnkota Power PSA. Minnesota Power has a PSA with Minnkota Power where Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold approximately 28 percent to Minnkota Power in 2021 (28 percent in 2020 and in 2019). Minnkota Power’s net entitlement increases to approximately 32 percent in 2022, 37 percent in 2023, 41 percent in 2024, 46 percent in 2025 and 50 percent in 2026. (See Power Supply – Long-Term Purchased Power.)

Silver Bay Power PSA. In 2016, Minnesota Power and Silver Bay Power entered into a PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which had previously been served predominately through self-generation by Silver Bay Power. Minnesota Power now supplies the full energy requirements for Silver Bay Power.

Seasonality

The operations of our industrial customers, which make up a large portion of our electric sales, are not typically subject to significant seasonal variations. (See Electric Sales / Customers.) As a result, Minnesota Power is generally not subject to significant seasonal fluctuations in electric sales; however, Minnesota Power and SWL&P electric and natural gas sales to other customers may be affected by seasonal differences in weather. In general, peak electric sales occur in the winter and summer months with fewer electric sales in the spring and fall months. Peak sales of natural gas generally occur in the winter months. Additionally, our regulated utilities have historically generated fewer sales and less revenue when weather conditions are milder in the winter and summer.

Power Supply

In order to meet its customers’ electric requirements, Minnesota Power utilizes a mix of its own generation and purchased power. As of December 31, 2021, approximately 50 percent of Minnesota Power’s power supply was provided by renewable energy sources. This was enabled by the completion of the 250 MW Nobles 2 wind energy facility in December 2020 and the GNTL in June 2020, which is used to deliver 250 MW of hydroelectric energy from Manitoba Hydro. Minnesota Power’s remaining operating coal-fired facilities are Boswell Units 3 and 4, which Minnesota Power proposed in its latest IRP to retire by 2030 and be coal-free by 2035, respectively. (See Regulatory Matters.) The following table reflects Minnesota Power’s generating capabilities as of December 31, 2021, and total electrical supply for 2021. Minnesota Power had an annual net peak load of 1,557 MW on July 26, 2021.

ALLETE, Inc. 2021 Form 10-K

12

REGULATED OPERATIONS (Continued)

Power Supply (Continued)

					Year Ended
	Unit	Year	Net		December 31, 2021
Regulated Utility Power Supply	No.	Installed	Capability		Generation and Purchases
			MW		MWh	%
Coal-Fired
Boswell Energy Center (a)	3	1973	355
in Cohasset, MN	4	1980	468	(b)
			823		4,451,706	28.2
Taconite Harbor Energy Center	1 & 2	1957	150	(c)	—	—
Total Coal-Fired			973		4,451,706	28.2
Biomass Co-Fired / Natural Gas
Hibbard Renewable Energy Center in Duluth, MN	3 & 4	1949, 1951	62		111,238	0.7
Laskin Energy Center in Hoyt Lakes, MN	1 & 2	1953	110		90,165	0.6
Total Biomass Co-Fired / Natural Gas			172		201,403	1.3
Hydro (d)
Group consisting of ten stations in MN	Multiple	Multiple	120		344,025	2.2
Wind (e)
Taconite Ridge Energy Center in Mtn. Iron, MN	Multiple	2008	25		55,178	0.3
Bison Wind Energy Center in Oliver and Morton Counties, ND	Multiple	2010-2014	497		1,533,048	9.7
Total Wind			522		1,588,226	10.0
Solar (f)
Group consisting of two solar arrays in MN	Multiple	Multiple	10		17,263	0.1
Total Generation			1,797		6,602,623	41.8
Long-Term Purchased Power
Lignite Coal - Square Butte near Center, ND (g)					1,488,785	9.4
Wind - Oliver Wind I and II in Oliver County, ND					374,217	2.4
Wind - Nobles 2 in Nobles County, MN (h)					936,312	5.9
Hydro - Manitoba Hydro in Manitoba, Canada					1,460,000	9.3
Total Long-Term Purchased Power					4,259,314	27.0
Other Purchased Power (i)					4,930,066	31.2
Total Purchased Power					9,189,380	58.2
Total Regulated Utility Power Supply					15,792,003	100.0

(a) Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. Minnesota Power proposed in its latest IRP to retire Boswell Unit 3 by 2030 and for Boswell Unit 4 to be coal-free by 2035. (See Regulatory Matters.)

(b)Boswell Unit 4 net capability shown above reflects Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 3. Jointly-Owned Facilities and Assets.)

(c)Taconite Harbor Units 1 and 2 were idled in 2016 and are planned to be retired once Minnesota Power’s 2021 IRP is approved. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

(d)Hydro consists of 10 stations with 34 generating units.

(e)Taconite Ridge consists of 10 WTGs and Bison consists of 165 WTGs.

(f)Solar includes the 10 MW Camp Ripley Solar Array near Little Falls, MN, and a 40 kW community solar garden in Duluth, MN.

(g)Minnesota Power has a PSA with Minnkota Power whereby Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power. (See Electric Sales / Customers – Minnkota Power PSA.)

(h)See Item 1. Business – Corporate and Other – Investment in Nobles 2.

(i)Includes short-term market purchases in the MISO market and from Other Power Suppliers.

ALLETE, Inc. 2021 Form 10-K

13

REGULATED OPERATIONS (Continued)

Power Supply (Continued)

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin region located in Montana and Wyoming. Coal consumption in 2021 for electric generation at Minnesota Power’s coal-fired generating stations was 2.7 million tons (2.2 million tons in 2020; 2.5 million tons in 2019). As of December 31, 2021, Minnesota Power had coal inventories of 0.4 million tons (0.8 million tons as of December 31, 2020). Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2022. In 2022, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. Minnesota Power continues to explore other future coal supply options and believes that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2024. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Coal Delivered to Minnesota Power
Year Ended December 31	2021	2020	2019
Average Price per Ton	$39.51	$34.94	$35.31
Average Price per MBtu	$2.18	$1.93	$1.94

Long-Term Purchased Power. Minnesota Power has contracts to purchase capacity and energy from various entities, including output from certain coal, wind, hydro and solar generating facilities.

Our PPAs are detailed in Note 8. Commitments, Guarantees and Contingencies, with additional disclosure provided in the following paragraph.

Square Butte PPA. Under the PPA with Square Butte that extends through 2026, Minnesota Power is entitled to 50 percent of the output of Square Butte’s 455 MW coal-fired generating unit. (See Note 8. Commitments, Guarantees and Contingencies.) BNI Energy mines and sells lignite coal to Square Butte. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit. Square Butte’s cost of lignite consumed in 2021 was approximately $1.94 per MBtu ($1.75 per MBtu in 2020; $1.88 per MBtu in 2019). (See Electric Sales / Customers – Minnkota Power PSA.)

Manitoba Hydro. Minnesota Power has three long-term PPAs with Manitoba Hydro. Under the first PPA, Minnesota Power is purchasing surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term. The second PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro through May 2035. The third PPA provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro through June 2040.

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (232 miles), 345 kV (241 miles), 250 kV (466 miles), 230 kV (715 miles), 161 kV (43 miles), 138 kV (130 miles), 115 kV (1,248 miles) and less than 115 kV (6,390 miles). We own and operate 159 substations with a total capacity of 10,086 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

Great Northern Transmission Line. As a condition of the 250 MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity was required. As a result, Minnesota Power constructed the GNTL, an approximately 220‑mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy. In June 2020, Minnesota Power placed the GNTL into service with project costs of approximately $310 million incurred by Minnesota Power. Total project costs, including those costs contributed by a subsidiary of Manitoba Hydro, totaled approximately $660 million. The 250 MW PPA with Manitoba Hydro commenced when the GNTL was placed into service.

ALLETE, Inc. 2021 Form 10-K

14

REGULATED OPERATIONS (Continued)

Investment in ATC

Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of December 31 2021, our equity investment in ATC was $154.5 million ($149.0 million as of December 31, 2020). (See Note 5. Equity Investments.)

ATC’s authorized return on equity is 10.02 percent, or 10.52 percent including an incentive adder for participation in a regional transmission organization, based on a 2020 FERC order that granted rehearing of a 2019 FERC order. These FERC orders are subject to various outstanding legal challenges related to the refund period ordered by the FERC. If these legal challenges are successful, ATC may be required to provide refunds to its customers of up to approximately $65 million of which our share would be approximately $5 million pre-tax. In addition, the FERC issued a Notice of Proposed Rulemaking in April 2021 proposing to limit the 50 basis point incentive adder for participation in a regional transmission organization to only the first three years of membership in such an organization. If this proposal is adopted, our equity in earnings from ATC would be reduced by approximately $1 million pre-tax annually.

ATC’s 10-year transmission assessment, which covers the years 2021 through 2030, identifies a need for between $3.5 billion and $4.2 billion in transmission system investments. These investments by ATC, if undertaken, are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC.

Properties

Our Regulated Operations businesses own office and service buildings, an energy control center, repair shops, electric plants, transmission facilities and storerooms in various localities in Minnesota, Wisconsin and North Dakota. All of the electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. Most of the generating plants and substations are located on real property owned by Minnesota Power or SWL&P, subject to the lien of a mortgage, whereas most of the transmission and distribution lines are located on real property owned by others with appropriate easement rights or necessary permits from governmental authorities. WPPI Energy owns 20 percent of Boswell Unit 4. WPPI Energy has the right to use our transmission line facilities to transport its share of Boswell generation. (See Note 3. Jointly-Owned Facilities and Assets.)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities and other organizations. Regulatory matters and proceedings are detailed in Note 4. Regulatory Matters, with a summary included in the following paragraphs.

Electric Rates. All rates and contract terms in our Regulated Operations are subject to approval by applicable regulatory authorities. Minnesota Power and SWL&P design their retail electric service rates based on cost of service studies under which allocations are made to the various classes of customers as approved by the MPUC or the PSCW. Nearly all retail sales include billing adjustment clauses, which may adjust electric service rates for changes in the cost of fuel and purchased energy, recovery of current and deferred conservation improvement program expenditures and recovery of certain transmission, renewable and environmental investments.

Minnesota Public Utilities Commission. The MPUC has regulatory authority over Minnesota Power’s retail service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters. Minnesota Power’s current retail rates are based on a 2018 MPUC retail rate order that allows for a 9.25 percent return on common equity and a 53.81 percent equity ratio. The resolution of Minnesota Power’s 2020 general rate case did not change the allowed return on equity or equity ratio. (See 2020 Minnesota General Rate Case.) As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission and renewable investments.

2020 Minnesota General Rate Case. In November 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing sought a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $66 million in additional revenue. In December 2019 orders, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $36.1 million beginning January 1, 2020.

ALLETE, Inc. 2021 Form 10-K

15

REGULATED OPERATIONS (Continued)

Regulatory Matters (Continued)

In April 2020, Minnesota Power filed a request with the MPUC that proposed a resolution of Minnesota Power’s 2020 general rate case. Key components of our proposal included removing the power marketing margin credit in base rates and reflecting actual power marketing margins in the fuel adjustment clause effective May 1, 2020; refunding to customers interim rates collected through April 2020; increasing customer rates 4.1 percent compared to the 5.8 percent increase reflected in interim rates; and a provision that Minnesota Power would not file another rate case until at least November 1, 2021, unless certain events occur. In a June 2020 order, the MPUC approved Minnesota Power’s petition and proposal to resolve and withdraw the general rate case. Effective May 1, 2020, customer rates were set at an increase of 4.1 percent with the removal of the power marketing margin credit from base rates. Actual power marketing margins will be reflected in the fuel adjustment clause. Reserves for interim rates of $11.7 million were recorded in the second quarter of 2020 and refunded in the third and fourth quarters of 2020.

2022 Minnesota General Rate Case. On November 1, 2021, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 18 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $108 million in additional revenue. In orders dated December 30, 2021, the MPUC accepted the filing as complete and authorized an annual interim rate increase beginning January 1, 2022, with approximately $80 million expected to be collected in cash and approximately $8 million of interim rates for residential customers deferred with a final determination on recovery at the end of the rate case.

Minnesota Power Land Sales. In August 2020, Minnesota Power filed a petition with the MPUC for approval to sell land that surrounds several reservoirs on its hydroelectric system and is no longer required to maintain its operations. The land has an estimated value of approximately $100 million, and Minnesota Power proposed to credit ratepayers the net proceeds from the sales in a future rate case or through its renewable resources rider to mitigate future rate increases. In an order dated November 18, 2021, the MPUC authorized the land sales and directed the net proceeds to be refunded to ratepayers subject to certain conditions and required compliance filings.

2021 Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP with the MPUC, which outlines its clean-energy transition plans through 2035. These plans include expanding its renewable energy supply to 70 percent by 2030, achieving coal-free operations at its facilities by 2035, and investing in a resilient and flexible transmission and distribution grid. Minnesota Power has also set a target to achieve an 80 percent reduction in carbon emissions by 2035 compared to 2005 levels. As part of these plans, Minnesota Power anticipates adding approximately 400 MW of new wind and solar energy resources, retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Minnesota Power’s plans recognize that advances in technology will play a significant role in completing its transition to carbon-free energy supply, reliably and affordably. A final decision on the IRP is expected in the second half of 2022.

Minnesota Power has a vision to deliver 100 percent carbon-free energy to customers by 2050, continuing its commitment to climate, customers and communities through its EnergyForward strategy. This vision builds on Minnesota Power’s recent achievement of now providing 50 percent renewable energy to its customers.

Public Service Commission of Wisconsin. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas and water, issuances of securities and other matters. SWL&P’s current retail rates are based on a December 2018 order that allows for a return on equity of 10.4 percent and a 55.0 percent equity ratio. The PSCW had directed SWL&P to file its next general rate case in 2020; however, the PSCW granted an extension request made by SWL&P to delay filing its next general rate case until on or before December 20, 2022. SWL&P requested the extension primarily due to impacts of the COVID-19 pandemic.

North Dakota Public Service Commission. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities in North Dakota.

Federal Energy Regulatory Commission. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for transmission of electricity in interstate commerce, electricity sold at wholesale (including the rates for Minnesota Power’s municipal and wholesale customers), natural gas transportation, certain accounting and record‑keeping practices, certain activities of our regulated utilities and the operations of ATC. FERC jurisdiction also includes enforcement of NERC mandatory electric reliability standards. Violations of FERC rules are subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

ALLETE, Inc. 2021 Form 10-K

16

REGULATED OPERATIONS (Continued)

Regional Organizations

Midcontinent Independent System Operator, Inc. Minnesota Power, SWL&P and ATC are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, their transmission networks are under the regional operational control of MISO. Minnesota Power and SWL&P take and provide transmission service under the MISO open access transmission tariff. In cooperation with stakeholders, MISO manages the delivery of electric power across 15 states and the Canadian province of Manitoba.

North American Electric Reliability Corporation. The NERC has been certified by the FERC as the national electric reliability organization. The NERC ensures the reliability of the North American bulk power system. The NERC oversees six regional entities that establish requirements, approved by the FERC, for reliable operation and maintenance of power generation facilities and transmission systems. Minnesota Power is subject to these reliability requirements and can incur significant penalties for non‑compliance.

Midwest Reliability Organization (MRO). Minnesota Power and ATC are members of the MRO, one of the six regional entities overseen by the NERC. The MRO's primary responsibilities are to: ensure compliance with mandatory reliability standards by entities who own, operate or use the interconnected, international bulk power system; conduct assessments of the grid's ability to meet electricity demand in the region; and analyze regional system events. The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, and all or parts of 16 states.

Minnesota Legislation

Renewable Energy. Minnesota law requires 25 percent of electric utilities’ applicable retail and municipal energy sales in Minnesota to be from renewable energy sources by 2025. Minnesota law also requires Minnesota Power to meet interim milestones including 20 percent by 2020. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power has exceeded the interim milestone requirements to date.

As of December 31, 2021, approximately 50 percent of Minnesota Power’s power supply was provided by renewable energy sources. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. Minnesota Power has met both parts of the solar mandate to date.

Competition

Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users of 2 MW and above that are located outside of a municipality are allowed to choose a supplier upon MPUC approval. Minnesota Power served 8 Large Power Customers under contracts of at least 10 MW in 2021, none of which have engaged in a competitive rate process. (See Electric Sales / Customers.) No other large commercial or small industrial customers in Minnesota Power’s service territory have sought a provider outside Minnesota Power’s service territory. Retail electric and natural gas customers in Wisconsin do not have the ability to choose their energy supplier. In both states, however, electricity may compete with other forms of energy. Customers may also choose to generate their own electricity, or substitute other forms of energy for their manufacturing processes.

In 2021, 4 percent of total regulated utility kWh sales were to municipal customers in Minnesota. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission was extended in 2020 and is effective through December 31, 2037. Minnesota Power’s wholesale electric contracts with 14 non-affiliated municipal customers are effective through varying dates ranging from 2024 through 2029. (See Electric Sales / Customers.)

ALLETE, Inc. 2021 Form 10-K

17

REGULATED OPERATIONS (Continued)

Competition (Continued)

The FERC has continued with its efforts to promote a competitive wholesale market through open-access electric transmission and other means. As a result, our electric sales to Other Power Suppliers and our purchases to supply our retail and wholesale load are made in a competitive market.

Franchises

Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 95 cities. The remaining cities, villages and towns served by Minnesota Power do not require a franchise to operate. SWL&P serves customers under electric, natural gas or water franchises in 1 city and 14 villages and towns.

ALLETE CLEAN ENERGY

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in seven states, more than 1,300 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 200 MW of wind energy facilities under contract to be sold to others. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – ALLETE Clean Energy.)

ALLETE Clean Energy believes the market for renewable energy in North America is robust, driven by several factors including environmental regulation, tax incentives such as the extension of production tax credit and investment tax credits, societal expectations and continual technology advances. State renewable portfolio standards, state or federal regulations to limit GHG emissions and the extension of production tax credit and investment tax credits are examples of environmental regulation or public policy that we believe will drive renewable energy development.

ALLETE Clean Energy’s strategy includes the safe, reliable, optimal and profitable operation of its existing facilities. This includes a strong safety culture, the continuous pursuit of operational efficiencies at existing facilities and cost controls. ALLETE Clean Energy generally acquires facilities in liquid power markets and its strategy includes the exploration of PSA extensions upon expiration of existing contracts, production tax credit requalification of existing facilities or the sale of facilities.

ALLETE, Inc. 2021 Form 10-K

18

ALLETE CLEAN ENERGY (Continued)

ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current operating portfolio is subject to typical variations in seasonal wind with higher wind resources typically available in the winter months. The majority of its planned maintenance leverages this seasonality and is performed during lower wind periods. ALLETE Clean Energy’s current operating portfolio is as follows:

Region	Wind Energy Facility	Capacity MW	PSA MW	PSA Expiration
East	Armenia Mountain	101	100%	2024
Midwest	Chanarambie/Viking	98
	PSA 1 (a)		12%	2023
	PSA 2		88%	2023
	Lake Benton	104	100%	2028
	Storm Lake I	108	100%	2027
	Storm Lake II	77
	PSA 1		90%	2022
	PSA 2		10%	2032
	Other	17	100%	2028
South	Caddo	303
	PSA 1		26%	2034
	PSA 2		66%	2034
	PSA 3		7%	2034
	Diamond Spring	303
	PSA 1		58%	2035
	PSA 2		25%	2032
	PSA 3		16%	2035
West	Condon	50	100%	2022
	Glen Ullin	106	100%	2039
	South Peak	80	100%	2035

(a)The PSA expiration assumes the exercise of four one-year renewal options that ALLETE Clean Energy has the sole right to exercise.

The majority of ALLETE Clean Energy’s wind operations are located on real property owned by others with easement rights or necessary consents of governmental authorities. One of ALLETE Clean Energy’s wind energy facilities is encumbered by liens against its assets securing financing. ALLETE Clean Energy’s Glen Ullin, South Peak, Diamond Spring and Caddo wind energy facilities are subject to tax equity financing structures. (See Note 1. Operations and Significant Accounting Policies.)

U.S. WATER SERVICES

U.S. Water Services provided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. In March 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained. The Company recognized a gain on the sale of U.S. Water Services of $13.2 million after-tax in 2019. ALLETE used the proceeds from the sale of U.S. Water Services to reinvest in growth initiatives at our Regulated Operations and ALLETE Clean Energy.

CORPORATE AND OTHER

BNI Energy

BNI Energy is a supplier of lignite coal in North Dakota, producing approximately 4 million tons annually and has an estimated 650 million tons of lignite coal reserves. Two electric generating cooperatives, Minnkota Power and Square Butte, consume virtually all of BNI Energy’s production of lignite under cost-plus fixed fee coal supply agreements extending through December 31, 2037. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 8. Commitments, Guarantees and Contingencies.) The mining process disturbs and reclaims between 200 and 250 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. As of December 31, 2021, BNI Energy’s total reclamation liability is estimated at $70.7 million and is included in Other Non-Current Liabilities on the Consolidated Balance Sheet. These costs are included in the cost-plus fixed fee contract, for which an asset reclamation cost receivable was included in Other Non-Current Assets on the Consolidated Balance Sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of credit. (See Note 8. Commitments, Guarantees and Contingencies.)

ALLETE, Inc. 2021 Form 10-K

19

CORPORATE AND OTHER (Continued)

Investment in Nobles 2

Our subsidiary, ALLETE South Wind, owns a 49 percent equity interest in Nobles 2, the entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. As of December 31, 2021, our equity investment in Nobles 2 was $163.5 million ($152.2 million at December 31, 2020). (See Note 5. Equity Investments.)

South Shore Energy

South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary, is developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to a capacity dedication agreement. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $700 million, of which South Shore Energy’s portion is expected to be approximately $150 million. South Shore Energy’s portion of NTEC project costs incurred through December 31, 2021, is approximately $5 million.

On October 1, 2021, South Shore Energy sold a portion of its undivided ownership interest in NTEC for approximately $20 million representing reimbursement of current costs plus a fee for prior development costs and risks incurred. Following the transaction, South Shore Energy now owns a 20 percent undivided ownership interest in NTEC, Basin owns a 30 percent undivided ownership interest in NTEC and Dairyland Power Cooperative continues to own a 50 percent undivided ownership interest in NTEC. The closing of the transaction resulted in the recognition of an approximately $8.5 million after-tax gain recorded in Corporate and Other in the fourth quarter of 2021, related to prior development costs and risks incurred.

ALLETE Properties

ALLETE Properties represents our legacy Florida real estate investment. ALLETE Properties’ major project in Florida is Town Center at Palm Coast, which consists of approximately 500 acres of land as well as various residential units and non-residential square footage. In addition to the Town Center at Palm Coast project, ALLETE Properties has approximately 500 acres of other land available for sale. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Corporate and Other – ALLETE Properties.)

Seller Financing. ALLETE Properties occasionally provides seller financing to qualified buyers. As of December 31, 2021, outstanding finance receivables were $7.6 million, net of reserves, with maturities through 2026. These finance receivables accrue interest at market-based rates and are collateralized by the financed properties.

Regulation. A substantial portion of our development properties in Florida are subject to federal, state and local regulations, and restrictions that may impose significant costs or limitations on our ability to develop the properties. Much of our property is vacant land and some is located in areas where development may affect the natural habitats of various protected wildlife species or in sensitive environmental areas such as wetlands.

Non-Rate Base Generation and Miscellaneous

Corporate and Other also includes other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 acres of land in Minnesota, and earnings on cash and investments.

As of December 31, 2021, non-rate base generation consists of 29 MW of natural gas and hydro generation at Rapids Energy Center in Grand Rapids, Minnesota, which is primarily dedicated to the needs of one customer, UPM Blandin.

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ENVIRONMENTAL MATTERS

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. (See Note 8. Commitments, Guarantees and Contingencies.)

HUMAN CAPITAL MANAGEMENT

The Company’s key human capital management objectives are to attract, recognize and retain high quality talent, align with strategic business objectives and support the Company’s values. To support these objectives, the Company’s programs are designed to develop talent; reward and support employees through competitive compensation programs and benefit plans; enhance the Company’s culture through efforts aimed at making the workplace more engaging, safe and inclusive; and acquire talent and leverage internal opportunities to create a high-performing, diverse workforce. Our management and Board of Directors play key roles in reviewing and overseeing our human capital practices.

As of December 31, 2021, ALLETE had 1,365 employees, of which 1,340 were full-time. Minnesota Power and SWL&P have an aggregate of 469 employees covered under collective bargaining agreements, of which most are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The current labor agreements with IBEW Local 31 expire on April 30, 2023 for Minnesota Power and January 31, 2024 for SWL&P. BNI Energy has 127 employees that are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2023.

Integrity. Integrity is a foundational, shared value at ALLETE, is important to ALLETE’s business and operations, and enables our success. The Company has a written Code of Ethics that applies to all of our employees.

Health and Safety. The success of our business is fundamentally connected to the well-being of our people. We continue to respond to the COVID-19 pandemic by taking steps to mitigate the potential risks to us posed by its transmission and have implemented company-wide business continuity plans in response to the pandemic. These plans guide our response, business continuity, and the precautionary measures we are taking on behalf of employees and the public.

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HUMAN CAPITAL MANAGEMENT (Continued)

Zero Injury Culture. Our journey to Zero Injury starts with a culture that is open and transparent. We encourage all employees to report injuries, near misses, and good catches, so that we can learn and share with others throughout the Company in an effort to improve safety performance. Leaders have regular safety conversations with employees, where the data learned from the conversations is examined, shared with the ALLETE safety strategy team and used to improve the Company’s safety programs. To monitor progress, the Company uses leading and lagging indicators to analyze injury trends, safety participation and other data to make better decision on safety practices.

Talent Attraction, Retention and Development. For more than a century, ALLETE has been successful because of our ability to attract and retain high-quality people who demonstrate our shared values. We engage in workforce planning, and succession planning, while building a robust talent pipeline and monitoring turnover.

We recognize and support the growth and development of our employees and offer opportunities to participate in internal and external learning programs. Our internal talent development programs provide employees with the resources they need to develop proficiency in their role, help achieve their career goals and build leadership skills. We are focusing initiatives on programs to expand the diversity of new hires and updating on-the-job trainings—including apprenticeships and scholarships aimed at bridging opportunity gaps—as we recognize the importance of a strong talent pipeline. In addition to role specific training, targeted training also includes respect in the workplace, cyber awareness, safety, integrity and leadership development.

Compensation and Benefits. Our competitive compensation package gives employees flexibility, choices and opportunities. Competitive compensation is important for the Company to attract and retain a qualified workforce to successfully manage our business and achieve our business objectives. We also strive to ensure pay equity amongst diverse employees performing equal or substantially similar work. Periodically, we review the median pay of our male and female employees as well as employees from diverse backgrounds.

Diversity, Equity and Inclusion. Increasing staff diversity enriches our workforce culture at ALLETE. Our employees are operating in an increasingly diverse society. In order to be accountable to our employees and stakeholders, we strive to have a workforce that reflects the diversity of the communities we serve, promotes inclusivity and is equitable.

At ALLETE, we want to ensure that we have a workplace culture where we treat each other with fairness, dignity and respect. The Company has a respect in the workplace initiative, which includes education as well as ongoing discussions focused on building respectful relationships and managing bias. We continue our efforts in crafting a framework to strengthen ALLETE’s diversity, equity and inclusion efforts in the areas of: workforce, supply chain and ALLETE as a community citizen. In 2021, ALLETE took tangible steps toward advancing diversity, equity and inclusion by continuing to raise awareness, furthering intentional external relationships/partnerships, increasing supplier diversity, focus on underrepresented groups through grants/scholarships and other Company and employee giving.

Yellow Ribbon Program. ALLETE and its subsidiaries are dedicated to supporting veterans, military members and their families. An employee effort grew out of that spirit of commitment to veterans and led the state of Minnesota to designate ALLETE/Minnesota Power and ALLETE Clean Energy as Yellow Ribbon Companies. The mission of ALLETE’s Yellow Ribbon Program is to contribute to the Company’s unique culture by proactively recruiting and retaining the best and supporting an environment in which military-connected employees can thrive.

AVAILABILITY OF INFORMATION

ALLETE makes its SEC filings, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(e) or 15(d) of the Securities Exchange Act of 1934, available free of charge on ALLETE’s website, www.allete.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

As of February 16, 2022, these are the executive officers of ALLETE:

Executive Officers	Initial Effective Date
Bethany M. Owen, Age 56
Chair, President and Chief Executive Officer	May 11, 2021
President and Chief Executive Officer	February 3, 2020
President	January 31, 2019
Senior Vice President and Chief Legal and Administrative Officer	November 26, 2016
Robert J. Adams, Age 59 (a)
Senior Vice President	February 9, 2022
Senior Vice President and Chief Financial Officer	March 4, 2017
Senior Vice President – Energy-Centric Businesses and Chief Risk Officer	November 14, 2015
Patrick L. Cutshall, Age 56
Vice President and Corporate Treasurer	December 18, 2017
Treasurer	January 1, 2016
Nicole R. Johnson, Age 47
Vice President and Chief Administrative Officer	June 28, 2019
Steven W. Morris, Age 60
Senior Vice President and Chief Financial Officer	February 9, 2022
Vice President and Chief Accounting Officer	October 28, 2021
Vice President, Controller and Chief Accounting Officer	December 24, 2016
Margaret A. Thickens, Age 55
Vice President, Chief Legal Officer and Corporate Secretary	February 13, 2019

(a)    On January 11, 2022, ALLETE announced the planned retirement of Robert J. Adams. As part of an orderly transition, Mr. Adams will remain at the Company until June 2022.

All of the executive officers have been employed by us for more than five years in executive or management positions. Prior to election to the position listed above, the following executives held other positions with the Company during the past five years.

Ms. Johnson was Vice President – Human Resources.

Ms. Thickens was General Counsel and Director of Compliance – ALLETE Clean Energy.

There are no family relationships between any of the executive officers. All officers and directors are elected or appointed annually.

The present term of office of the executive officers listed in the preceding table extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 10, 2022.

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Item 1A. Risk Factors

The risks and uncertainties discussed below could materially affect our business operations, financial position, results of operations and cash flows, and should be carefully considered by stakeholders. The risks and uncertainties in this section are not the only ones we face; additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations, financial position, results of operations and cash flows. Accordingly, the risks described below should be carefully considered together with other information set forth in this report and in future reports that we file with the SEC.

Regulated Operations Risks

Our results of operations could be negatively impacted if our taconite, paper and pipeline customers experience an economic downturn, incur work stoppages, fail to compete effectively, experience decreased demand, fail to economically obtain raw materials, fail to renew or obtain necessary permits, or experience a decline in prices for their product.

Minnesota Power’s Large Power Customers (see Item 1. Business – Regulated Operations – Electric Sales / Customers) and Silver Bay Power accounted for 32 percent of our 2021 consolidated operating revenue (29 percent in 2020 and 30 percent in 2019) and 37 percent of Regulated Operations operating revenue (34 percent in 2020 and 36 percent in 2019). Minnesota Power’s taconite customers, which are currently owned by only two entities at the end of 2021, accounted for approximately 28 percent of consolidated operating revenue and 32 percent of Regulated Operations operating revenue in 2021. These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the marketplace. The North American paper and pulp industry also faces declining demand due to the impact of electronic substitution for print and changing customer needs. As a result, certain paper and pulp customers have reduced their existing operations or idled facilities in recent years and have pursued or are pursuing product changes in response to declining demand. Additionally, the taconite industry could be impacted by changing technology in the steel industry such as the adoption of electric arc furnaces for steelmaking, which could result in declining demand for taconite and the electricity used during its production.

Minnesota Power also serves two pipeline customers that accounted for 2 percent of our 2021 consolidated operating revenue (2 percent in 2020 and in 2019) and 2 percent of Regulated Operations revenue in 2021 (3 percent in 2020 and 3 percent in 2019). These customers are involved in an industry that is seeing increased environmental pressure for construction of new or expanded pipeline infrastructure for the transportation of fossil fuels. Changes in regulatory rulings or permit proceedings could result in changes to operations of the pipeline network in our service territory.

Accordingly, if our industrial customers experience an economic downturn, incur a work stoppage (including strikes, lock-outs or other events), fail to compete effectively, experience decreased demand, fail to economically obtain raw materials, fail to renew or obtain necessary permits, or experience a decline in prices for their product, there could be adverse effects on their operations and, consequently, this could have a negative impact on our results of operations as we are unable to remarket at similar prices the energy that would otherwise have been sold to such customers. These customers have also been impacted by the ongoing COVID-19 pandemic. (See Entity-wide Risks.)

We may not be able to successfully implement our strategic objectives of growing load at our utilities if current or potential industrial or municipal customers are unable to successfully implement expansion plans, including the inability to obtain necessary governmental permits and approvals.

As part of our long-term strategy, we pursue new wholesale and retail loads in and around our service territories. Currently, there are several companies in northeastern Minnesota that are in the process of developing natural resource-based projects that represent long-term growth potential and load diversity for our Regulated Operations businesses. These projects may include construction of new facilities and restarts of old facilities, both of which require permitting and approvals to be obtained before the projects can be successfully implemented. If a project does not obtain any necessary governmental (including environmental) permits and approvals or if these customers are unable to successfully implement expansion plans, our long-term strategy and thus our results of operations could be adversely impacted.

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

Our businesses, investments and customers are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

Our businesses, investments and customers are subject to an extensive legal and regulatory framework imposed under federal and state law including regulations administered by the FERC, MPUC, MPCA, PSCW, NDPSC and EPA as well as regulations administered by other organizations including the NERC. These laws and regulations relate to allowed rates of return, capital structure, financings, rate and cost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and distribution facilities (including the ongoing maintenance and reliable operation of such facilities), recovery of purchased power costs and capital investments, approval of integrated resource plans and present or prospective wholesale and retail competition, renewable portfolio standards that require utilities to obtain specified percentages of electric supply from eligible renewable generation sources, among other things. Energy policy initiatives at the state or federal level could increase renewable portfolio standards or incentives for distributed generation, municipal utility ownership, or local initiatives could introduce generation or distribution requirements that could change the current integrated utility model. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. Compliance with these standards may lead to increased operating costs and capital expenditures which are subject to regulatory approval for recovery. If it was determined that we were not in compliance with these mandatory reliability standards or other statutes, rules and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations.

These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary permits, licenses, approvals and certificates for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations, timing of approvals, the adoption of new regulations or the expansion of jurisdiction by these agencies and other organizations could have an adverse impact on our business and results of operations.

Our ability to obtain rate adjustments to maintain reasonable rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or reasonable authorized rates of return on capital will be earned. Minnesota Power and SWL&P, from time to time, file general rate cases with, or otherwise seek cost recovery authorization from, federal and state regulatory authorities. If Minnesota Power and SWL&P do not receive an adequate amount of rate relief in general rate cases, including if rates are reduced, if increased rates are not approved or recovered on a timely basis, if fuel adjustment clause recoveries or cost recovery for other items are not granted at the requested level, or costs are otherwise unable to be recovered through rates, we may experience an adverse impact on our financial position, results of operations and cash flows. We are unable to predict the impact on our business and results of operations from future legislation or regulatory activities of any of these agencies or organizations.

Our regulated operations present certain environmental risks that could adversely affect our financial position and results of operations, including effects of environmental laws and regulations, physical risks associated with climate change and initiatives designed to reduce the impact of GHG emissions.

We are subject to extensive environmental laws and regulations affecting many aspects of our past, present and future operations, including air quality, water quality and usage, waste management, reclamation, hazardous wastes, avian mortality and natural resources. These laws and regulations, or new laws and regulations that may be passed, can result in increased capital expenditures and increased operating and other costs as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to emissions, coal ash and water discharge at generating facilities.

These laws and regulations could restrict the output of some existing facilities, limit the use of some fuels in the production of electricity, require the installation of additional pollution control equipment, require participation in environmental emission allowance trading, and lead to other environmental considerations and costs, which could have an adverse impact on our business, operations and results of operations.

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Violations of these laws and regulations could expose us to regulatory and legal proceedings, disputes with, and legal challenges by, governmental authorities and private parties, as well as potential significant civil fines criminal penalties and other sanctions.

Existing environmental regulations may be revised and new environmental regulations may be adopted or become applicable to us. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have an adverse effect on our results of operations.

There is significant uncertainty regarding if and when new laws, regulations or administrative policies will be adopted to reduce or limit GHG and the impact any such laws or regulations would have on us. In 2021, our operating coal-fired generating facilities consisted of the 355 MW Boswell Unit 3 and the 468 MW Boswell Unit 4. (See Outlook – EnergyForward.) Any future limits on GHG emissions at the federal or state level, or action taken by regulators, before these facilities are retired or become coal-free may require us to incur significant capital expenditures and increases in operating costs, or could result in early closure of coal-fired generating facilities, stranded assets, an impairment of assets, denial of full recovery of decommissioning costs in excess of amounts previously collected, or otherwise adversely affect our results of operations, particularly if resulting expenditures and costs are not fully recoverable from customers.

Our regulated operations may be adversely impacted by the physical and financial risks associated with climate change. See Entity-wide Risks for additional discussion of risks related to GHG and climate change.

We cannot predict the amount or timing of all future expenditures related to environmental matters because of uncertainty as to applicable regulations or requirements. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Violations of certain environmental statutes, rules and regulations could expose ALLETE to third party disputes and potentially significant monetary penalties, as well as other sanctions for non‑compliance.

The operation and maintenance of our regulated electric generation and transmission facilities are subject to operational risks that could adversely affect our financial position, results of operations and cash flows.

The operation of generating facilities involves many risks, including start-up operational risks, breakdown or failure of facilities, the dependence on a specific fuel source, inadequate fuel supply, availability of fuel transportation, and the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. A significant portion of our facilities contain older generating equipment, which, even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. Generation and transmission facilities and equipment are also likely to require periodic upgrades and improvements due to changing environmental standards and technological advances. We could be subject to costs associated with any unexpected failure to produce or deliver power, including failure caused by breakdown, forced outage or limited availability of fuel or fuel transportation, as well as the repair of damage to facilities due to breakdown, storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events. This could also lead to requiring additional purchased power to meet requirements of serving our retail load, which for Minnesota Power is subject to recovery under the fuel adjustment clause. Should these costs be denied or are otherwise unable to be recovered, our financial position, results of operations and cash flows could be adversely impacted.

Our ability to successfully and timely complete capital repairs or improvements to existing regulated facilities or other capital projects is contingent upon many variables.

We expect to incur significant capital expenditures in making capital repairs or improvements to our existing electric generation and transmission facilities and in the development and construction of new electric generation and transmission facilities. Should any such efforts be unsuccessful, not completed in a timely manner or if there are increases in the costs for or limited availability of key materials, supplies, labor and services, we could be subject to additional costs or impairments which could have an adverse impact on our financial position, results of operation and cash flows.

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

Our regulated electric generating operations may not have access to adequate and reliable transmission and distribution facilities necessary to deliver electricity to our customers.

We depend on our own transmission and distribution facilities, as well as facilities owned by other utilities, to deliver the electricity produced and sold to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be limited. We may have to forgo sales or may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact the satisfaction of our customers, which could have an adverse impact on our business and results of operations.

The price of electricity may be volatile and fuel may be volatile and availability may be limited.

Volatility in market prices for electricity and volatility and limited availability of fuel could adversely impact our financial position and results of operations and may result from:

•severe or unexpected weather conditions and natural disasters;

•seasonality;

•changes in electricity usage;

•transmission or transportation constraints, inoperability or inefficiencies;

•availability of competitively priced alternative energy sources;

•changes in supply and demand for energy;

•changes in power production capacity;

•outages at our generating facilities or those of our competitors;

•availability of fuel and transportation of fuel;

•changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;

•wars, sabotage, terrorist acts or other catastrophic events; and

•federal, state, local and foreign energy, environmental, or other regulation and legislation.

Volatility in market prices for our fuel and purchase power costs impacts our sales to retail, municipal and Other Power Suppliers. Fluctuations in our fuel and purchased power costs related to our retail and municipal customers are passed on to customers through the fuel adjustment clause; however, our results of operations and cash flows may be adversely impacted if increased fuel adjustment clause rates are not approved or recovered on a timely basis, if cost recovery is not granted at the requested level, or costs are otherwise unable to be recovered through the fuel adjustment clause.

Wholesale prices for electricity have also declined in recent years primarily due to low natural gas prices, the extension of renewable tax credits and additional renewable generation commencing operations. If there are reductions in demand from current customers, we lose retail customers, or we lose municipal customers that do not renew existing contracts, we will market any available power to Other Power Suppliers in an effort to mitigate any earnings impact. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. Due to wholesale prices for electricity being below our rates for retail and municipal customers, we do not expect that our power marketing efforts would fully offset the reduction in earnings resulting from the lower demand from existing customers or the loss of customers. (See Item 1. Business – Regulated Operations – Electric Sales / Customers.)

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

Demand for energy may decrease.

Our results of operations are impacted by the demand for energy in our service territories, our municipal customers and other power suppliers. There could be lower demand for energy due to a loss of customers as a result of economic conditions, customers constructing or installing their own generation facilities, higher costs and rates charged to customers, eligible municipal and other power suppliers choosing an alternative energy provider, or loss of service territory or franchises. Further, energy conservation and technological advances that increased energy efficiency may temporarily or permanently reduce the demand for energy products. In addition, we are impacted by state and federal regulations requiring mandatory conservation measures, which reduce the demand for energy products. Continuing technology improvements and regulatory developments may make customer and third party-owned generation technologies such as rooftop solar systems, WTGs, microturbines and battery storage systems more cost effective and feasible for of our customers. If customers utilize their own generation, demand for energy from us would decline. There may not be future economic growth opportunities that would enable us to replace the lost energy demand from these customers. Therefore, a decrease in demand for energy could adversely impact our financial position, results of operations and cash flows.

ALLETE Clean Energy / Corporate and Other Risks

The inability to successfully manage and grow ALLETE Clean Energy and our Corporate and Other businesses could adversely affect our results of operations.

The Company's strategy includes adding customers, new geographies, and growth through acquisitions or project development with long-term PSAs in place for the output or to be sold upon completion. This strategy depends, in part, on the Company’s ability to successfully identify and evaluate acquisition or development opportunities and consummate acquisitions on acceptable terms. The Company may compete with other companies for these acquisition and development opportunities, which may increase the Company’s cost of making acquisitions and the Company may be unsuccessful in pursuing these acquisition opportunities. Other companies may be able to pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets than the Company’s financial or human resources permit. New laws and regulations promoting renewable energy generation may result in increased competition. Our ALLETE Clean Energy business is experiencing return pressures from increased competition, and lower forward price curves, as a growing amount of investment capital is being directed into wind generation opportunities. In addition, current and potential new project developments can be negatively affected by a lower ALLETE stock price, which may result in such projects not being accretive, or otherwise unable to satisfy our financial objectives criteria to proceed. Additionally, tax law changes may adversely impact the economic characteristics of potential acquisitions or investments. Any reductions or modifications to, or the elimination of, governmental incentives or policies that support renewable energy or the imposition of additional taxes or other assessments on renewable energy, could result in, among other items, the lack of a satisfactory market for the development or financing of new renewable energy projects and reduced project returns on future projects. If the Company is unable to execute its strategy of growth through acquisitions, project development for others, or the addition of new customers and geographies, it may impede our long-term objectives and business strategy.

Acquisitions are subject to uncertainties. If we are unable to successfully integrate and manage future acquisitions or strategic investments, this could have an adverse impact on our results of operations. Our actual results may also differ from our expectations due to factors such as the ability to obtain timely regulatory or governmental approvals, integration and operational issues and the ability to retain management and other key personnel.

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Item 1A. Risk Factors (Continued)

ALLETE Clean Energy / Corporate and Other Risks (Continued)

The generation of electricity from wind and solar energy facilities depends heavily on suitable meteorological conditions.

Although our electric generation facilities are located in diverse geographic regions to reduce the potential impact that may be caused by unfavorable weather in a particular region, suitable meteorological conditions are variable and difficult to predict. If wind or solar conditions are unfavorable or meteorological conditions are unsuitable, electricity generation and revenue from wind and solar energy facilities may be substantially below our expectations. The electricity produced, production tax credits received, and revenues generated by a wind or solar energy facility are highly dependent on suitable wind conditions and associated weather conditions, which are variable and beyond our control. We base our decisions about which wind and solar projects to build or acquire as well as our electricity generation estimates, in part, on the findings of long-term wind and other meteorological studies conducted on the project site and its region; however, the unpredictable nature of wind and solar conditions, weather and meteorological conditions can result in material deviations from these studies and our expectations. Furthermore, components of our systems could be damaged by severe weather, such as hailstorms, lightning or tornadoes. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable. Unfavorable wind and solar conditions, weather or changes to meteorological patterns could impair the effectiveness of our electric generation facility assets, reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of our wind energy facilities or lead to an impairment of assets.

The construction, operation and maintenance of our electric generation facilities or investment in facilities are subject to operational risks that could adversely affect our financial position, results of operations and cash flows.

The construction and operation of generating facilities involves many risks, including the performance by key contracted suppliers and maintenance providers; increases in the costs for or limited availability of key materials, supplies, labor and services; start-up operations risks; breakdown or failure of facilities; curtailment of facilities by counterparties; the dependence on the availability of wind resources; or the impact of unusual, adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. Some of our facilities contain older generating equipment, which even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. We could be subject to costs associated with any unexpected failure to produce and deliver power, including failure caused by breakdown or forced outage, as well as the repair of damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events.

The price of electricity may be volatile, which may impact results of operations at ALLETE Clean Energy wind energy facilities under contracts with customer and industrial (C&I) customers.

Unusual, adverse weather conditions or other natural events can cause volatility in market prices for electricity and adversely affect our financial position, results of operations and cash flows. ALLETE Clean Energy’s power sales agreements with its three C&I customers at its Diamond Spring wind energy facility are contracts for differences where power is delivered to the market, and a fixed price is paid by the customers to ALLETE Clean Energy, and differences between the market price and the fixed price are paid to or received from the customers. One of these power sales agreements settles with the customer based on day-ahead electricity prices, while deliveries to the market are settled based on real-time electricity prices. This settlement provision can and has resulted in an adverse impact to the Company when market prices are extremely volatile as happened in February 2021 during an extreme winter weather event in the southwest United States. This winter weather event caused extreme volatility, with large differences in the day-ahead and real-time market prices; the settlement provision resulted in an approximately $5 million after-tax negative impact related to the Diamond Spring wind energy facility in 2021.

As contracts with counterparties expire, we may not be able to replace them with agreements on similar terms or divest the related assets at a profit.

ALLETE Clean Energy is party to PSAs which expire in various years between 2022 and 2039. These PSA expirations are prior to the end of the estimated useful lives of the respective wind energy facilities. If, for any reason, ALLETE Clean Energy is unable to enter into new agreements with existing or new counterparties on similar terms once the current agreements expire, sell energy in the wholesale market resulting in similar revenue, or enter into a contract to sell the facility at a profit, our financial position, results of operations and cash flows could be adversely affected, which includes potential impairment of property, plant and equipment.

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Item 1A. Risk Factors (Continued)

ALLETE Clean Energy / Corporate and Other Risks (Continued)

Counterparties to turbine and other generation supply, service and maintenance, or power sale agreements may not fulfill their obligations.

Our businesses are party to turbine and other generation supply agreements, service and maintenance agreements, and PSAs under various durations with a limited number of creditworthy counterparties. If, for any reason, any of the counterparties under these agreements do not fulfill their related contractual obligations, and we are unable to mitigate non-performance by a key supplier or maintenance provider or remarket PSA energy resulting in similar revenue, our financial position, results of operations and cash flows could be adversely affected.

BNI Energy may be adversely impacted by its exposure to customer concentration, and environmental laws and regulations.

BNI Energy sells lignite coal to two electric generating cooperatives, Minnkota Power and Square Butte, and could be adversely impacted if these customers were unable or unwilling to fulfill their related contractual obligations, or change the way in which they operate their generating facilities. In addition, BNI Energy and its customers may be adversely impacted by existing or new environmental laws and regulations which could have an adverse effect on our financial position, results of operations and cash flows. In addition, insurance companies have decreased the available coverage for policy holders in the mining industry, impacting the availability of coverage, and leading to higher deductibles and premiums.

Real estate market conditions where our legacy Florida real estate investment is located may deteriorate.

The Company’s strategy related to the real estate assets of ALLETE Properties incorporates the possibility of a bulk sale of its entire portfolio, in addition to sales over time, however, adverse market conditions could impact the timing of land sales, which could result in little to no sales, while still incurring operating expenses such as community development district assessments and property taxes, resulting in net operating losses at ALLETE Properties. Furthermore, weak market conditions could put the properties at risk for an impairment charge. An impairment charge would result in a non-cash charge to earnings that could have an adverse effect on our results of operations.

Entity-wide Risks

We could be materially adversely affected by health epidemics, pandemics and other outbreaks, such as the ongoing COVID-19 pandemic.

The ongoing COVID-19 pandemic has resulted in widespread impacts on the global economy and on our employees, customers, contractors, and suppliers. There is considerable uncertainty regarding the length of time for which COVID-19 will continue, if new variants will emerge or the extent and duration of measures to try to contain the virus. We are responding to the COVID-19 pandemic by taking steps to mitigate the potential risks to us posed by its transmission and have implemented company-wide business continuity plans in response to the pandemic. These plans guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We have taken additional precautions for our employees who work in the field and for employees who continue to work in our facilities, and we have implemented work from home policies where appropriate. We continue to implement physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.

The ongoing COVID-19 pandemic and related federal and state government responses has led to a disruption of economic activity, and could result in an extended disruption of economic activity. Further disruption of economic activity or an extended disruption of economic activity may lead to additional adverse impacts on our taconite, paper, pulp and secondary wood products, and pipeline customers’ operations including reduced production or the temporary idling or indefinite shutdown of facilities, which would result in lower sales and revenue from these customers.

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

The Company is monitoring the capital markets and has access to liquidity to enable us to operate our businesses and fund capital projects; however, a disruption in capital markets could lead to increased borrowing costs or adversely impact our ability to access capital markets or other financing sources. If we are not able to access capital on acceptable terms in sufficient amounts and when needed, or at all, the ability to maintain our businesses or to implement our business plans would be adversely affected. In addition, the performance of capital markets impacts the values of the assets that are held in trust to satisfy future obligations under our pension and other postretirement benefit plans. A decline in the market value of these assets would increase the funding requirements under our benefit plans and future costs recognized for the benefit plans if the asset market values do not recover. The Company is also monitoring supply chains for key materials, supplies, labor and services for our operations and large capital projects. The pandemic could result in a disruption to our supply chains which could adversely impact our operations and capital projects. There has been some impact on our supply chains as to the availability of and price for materials, supplies and services to date. In addition, disruptions in our supply chains or a lack of available financing could jeopardize our ability to complete certain capital projects in time to qualify them for production tax credits.

We will continue to monitor developments affecting our workforce, operations and customers, and we will take additional precautions that we determine are necessary in order to mitigate the impacts of the COVID-19 pandemic. Despite our efforts to manage these impacts to the Company, their ultimate impact also depends on factors beyond our control, including the duration and severity of this pandemic as well as governmental and third-party actions taken to contain its spread and mitigate its public health effects. As a result, we cannot predict the ultimate impact of the COVID-19 pandemic and whether it will have a material impact on our liquidity, financial position, results of operations and cash flows.

We rely on access to financing sources and capital markets. If we do not have access to capital on acceptable terms or are unable to obtain capital when needed, our ability to execute our business plans, make capital expenditures or pursue other strategic actions that we may otherwise rely on for future growth would be adversely affected.

We rely on access to financing sources and the capital markets, on acceptable terms and at reasonable costs, as sources of liquidity for capital requirements not satisfied by our cash flows from operations. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access and finance in the capital markets or to access other financing sources such as tax equity financing. Such disruptions or causes of a downgrade could include but are not limited to: weakening of the Company’s cash flow metrics; a loss of, or a reduction in sales to, our taconite, paper and pipeline customers if we are unable to offset the related lost margins; weaker operating performance; adverse regulatory outcomes; disproportionate increase in the contribution to net income from ALLETE Clean Energy and our Corporate and Other businesses as compared to that from our Regulated Operations; deteriorating economic or capital market conditions; or volatility in commodity prices.  

If we are not able to access capital on acceptable terms in sufficient amounts and when needed, or at all, the ability to maintain our businesses or to implement our business plans would be adversely affected.

A deterioration in general economic conditions, an inflationary environment or supply chain disruptions may have adverse impacts on our financial position, results of operations and cash flows.

If economic conditions deteriorate, we experience an inflationary environment or supply chains are disrupted on a national or regional level, it may have a negative impact on the Company’s financial position, results of operations and cash flows as well as on our customers. This impact may include volatility and unpredictability in the demand for the products and services offered by our businesses, the loss of existing customers, tempered growth strategies, customer production cutbacks, customer bankruptcies and increases in costs for or limited availability of key materials, supplies, labor and services for our operations and capital projects. An uncertain economy could also adversely affect expenses including pension costs, interest costs, and uncollectible accounts, or lead to reductions in the value of certain real estate and other investments.

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

Our businesses, investments and customers are subject to extensive state and federal legislation and regulation, compliance with which could have an adverse effect on our businesses.

Our businesses, investments and customers are subject to, and affected by, extensive state and federal legislation and regulation. If it was determined that our businesses failed to comply with applicable laws and regulations, we could become subject to fines or penalties or be required to implement additional compliance measures or actions, the cost of which could be material. Adoption of new laws, rules, regulations, principles, or practices by federal and state agencies, or changes to or a failure to comply with current laws, rules, regulations, principles, or practices and their interpretations, could have an adverse effect on our financial position, results of operations and cash flows.

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on our operations.

The success of our business heavily depends on the leadership of our executive officers and key employees to implement our business strategy. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. Personnel costs may increase due to competitive pressures, inflation or terms of collective bargaining agreements with union employees.

Market performance and other changes could decrease the value of pension and other postretirement benefit plan assets, which may result in significant additional funding requirements and increased annual expenses.

The performance of the capital markets impacts the values of the assets that are held in trust to satisfy future obligations under our pension and other postretirement benefit plans. We have significant obligations to these plans and the trusts hold significant assets. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. A decline in the market value of the pension and other postretirement benefit plan assets would increase the funding requirements under our benefit plans if asset returns do not recover. Additionally, our pension and other postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Our pension and other postretirement benefit plan costs are generally recoverable in our electric rates as allowed by our regulators or through our cost-plus fixed fee coal supply agreements at BNI Energy; however, there is no certainty that regulators will continue to allow recovery of these rising costs in the future.

We are exposed to significant reputational risk.

The Company could suffer negative impacts to its reputation as a result of operational incidents, violations of corporate compliance policies, regulatory violations, or other events which may result in negative customer perception and increased regulatory oversight, each of which could have an adverse effect on our financial position, results of operations and cash flows.

We are subject to physical and financial risks associated with climate change and other catastrophic events, such as natural disasters and acts of war.

Catastrophic events at or near Company facilities and equipment on which the Company depends upon or that otherwise impact the Company such as fires, wildfires, including the impact to Company facilities and operations or potential liability if caused by Company equipment, earthquakes, explosions, and floods, severe weather, such as ice storms, hailstorms, or tornadoes or similar occurrences, as well as acts of war, could adversely affect the Company’s facilities, operations, financial position, results of operations and cash flows. Although the Company has contingency plans and employs crisis management to respond and recover operations in the event of a severe disruption resulting from a catastrophic event, these measures may not be successful. Furthermore, despite these measures, if a catastrophic event were to occur, our financial position, results of operations and cash flows could be adversely affected.

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

The scientific community generally accepts that emissions of GHG are linked to global climate change. Physical risks of climate change, such as more frequent, longer duration or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs or limit the availability of key materials, supplies, labor and services. An extreme weather event can also directly affect our capital assets, causing disruption in service to customers due to facility outages, downed wires and poles or damage to other operating equipment.

Climate-related risks that could adversely affect our financial position and results of operations include effects of environmental- or economic-based laws, regulations, incentives or initiatives designed to reduce the quantity or impact of GHG emissions. This includes the risk of laws or regulations that create mandates that do not allow for a transition that protects the safety, reliability or affordability of energy for our customers, are implemented before cost-effective technology is developed and regulatory policy is established, or require the electric sector to decarbonize faster than other sectors and ahead of our current goal to deliver 100 percent carbon-free energy to customers by 2050. Additionally, restrictions on land use, wildlife impacts, and other environmental regulations could affect the siting, construction and operation of new or existing generation and transmission facilities needed to transition to lower-carbon generation sources.

These all have the potential to adversely affect our business and operations.

We are vulnerable to acts of terrorism or cybersecurity attacks.

Our operations may be targets of terrorist activities or cybersecurity attacks, which could disrupt our ability to provide utility service at our regulated utilities, develop or operate our renewable energy projects at ALLETE Clean Energy, or operate our other businesses. The impacts may also impair the fulfillment of critical business functions, negatively impact our reputation, subject us to litigation or increased regulation, or compromise sensitive, confidential and other data.

There have been cybersecurity attacks on U.S. energy infrastructure in the past and there may be such attacks in the future. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or otherwise be materially adversely affected by such activities. Hacking, computer viruses, terrorism, theft and sabotage could impact our systems and facilities, or those of third parties on which we rely, which may disrupt our operations.

Our businesses require the continued operation of sophisticated custom-developed, purchased, and leased information technology systems and network infrastructure as well as the collection and retention of personally identifiable information of our customers, shareholders and employees. Although we maintain security measures designed to prevent cybersecurity incidents and protect our information technology and control systems, network infrastructure and other assets, our technology systems, or those of third parties on which we rely, may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism as well as other causes. If those technology systems fail or are breached and not recovered in a timely manner, we may be unable to perform critical business functions including effectively maintaining certain internal controls over financial reporting, our reputation may be negatively impacted, we may become subject to litigation or increased regulation, and sensitive, confidential and other data could be compromised. If our business were impacted by terrorist activities or cybersecurity attacks, such impacts could have an adverse effect on our financial position, results of operations and cash flows.

We maintain insurance against some, but not all, of the risks and uncertainties we face.

We maintain insurance against some, but not all, of the risks and uncertainties we face. The occurrence of these risks and uncertainties, if not fully covered by insurance, could have a material effect on our financial position, results of operations and cash flows.

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

Government challenges to our tax positions, as well as tax law changes and the inherent difficulty in quantifying potential tax effects of our operations and business decisions, could adversely affect our results of operations and liquidity.

We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations in order to estimate our obligations to taxing authorities. The obligations, which include income taxes and taxes other than income taxes, involve complex matters that ultimately could be litigated. We also estimate our ability to use tax benefits, including those in the form of carryforwards and tax credits that are recorded as deferred tax assets on our Consolidated Balance Sheet. A disallowance of some or all of these tax benefits could have an adverse impact on our financial position, results of operations and cash flows.

We are currently utilizing, and plan to utilize in the future, our carryforwards and tax credits to reduce our income tax obligations. If we cannot generate enough taxable income in the future to utilize all of our carryforwards and tax credits before they expire, we may incur adverse charges to earnings.

If federal or state tax authorities deny any deductions or tax credits, negatively change existing tax laws or policies, or fail to extend or renew policies beneficial to the Company, such as those for renewable energy production tax credits, our financial position, results of operations and cash flows may be adversely impacted.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

A discussion of our properties is included in Item 1. Business and is incorporated by reference herein.

Item 3. Legal Proceedings

Discussions of material regulatory and environmental proceedings are included in Note 4. Regulatory Matters and Note 8. Commitments, Guarantees and Contingencies, and are incorporated by reference herein.

We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

Minnesota Power has been named in a lawsuit where a contractor performing work at one of its facilities experienced an injury and subsequently filed a lawsuit seeking compensatory damages. Litigation related to this injury is ongoing. At this time, a loss is considered reasonably possible; however, we do not deem it probable, and we are unable to estimate a loss or range of loss related to the litigation at this time.

Item 4. Mine Safety Disclosures

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and this Item are included in Exhibit 95 to this Form 10-K.

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Part II

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

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends, without interruption, on our common stock since 1948. A quarterly dividend of $0.65 per share on our common stock is payable on March 1, 2022, to the shareholders of record on February 15, 2022. The timing and amount of future dividends will depend upon earnings, cash requirements, the financial condition of the Company, applicable government regulations and other factors deemed relevant by the ALLETE Board of Directors. As of February 1, 2022, there were approximately 20,000 common stock shareholders of record.

Performance Graph.

The following graph compares ALLETE’s cumulative Total Shareholder Return on its common stock with the cumulative return of the S&P 500 Index and the Philadelphia Utility Index. The S&P 500 Index is a capitalization-weighted index of 500 stocks designed to measure performance of the broad domestic economy through changes in the aggregate market value of 500 stocks representing all major industries. Because this composite index has a broad industry base, its performance may not closely track that of a composite index comprised solely of electric utilities. The Philadelphia Utility Index is a capitalization-weighted index of 20 utility companies involved in the generation of electricity.

The calculations assume a $100 investment on December 31, 2016, and reinvestment of dividends.

	2016	2017	2018	2019	2020	2021
ALLETE	$100	$119	$126	$138	$110	$122
S&P 500 Index	$100	$122	$116	$153	$181	$233
Philadelphia Utility Index	$100	$113	$117	$148	$152	$180

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Item 6. [Reserved]

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

The following discussion should be read in conjunction with our Consolidated Financial Statements and notes to those statements and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-K contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-K under the headings: “Forward‑Looking Statements” located on page 6 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the risks are realized.

The trends and results for the year ended December 31, 2021, may not be indicative of future results that may be expected due to uncertainty regarding the COVID-19 pandemic. This pandemic has resulted in widespread impacts on the global economy and on our employees, customers, contractors, and suppliers. There is considerable uncertainty regarding the length of time for which COVID-19 will continue, if new variants will emerge or the extent and duration of measures to try to contain the virus. Additional disclosures in this Form 10-K regarding the impacts of the ongoing COVID-19 pandemic are located in Item 1A. Risk Factors.

Overview

Basis of Presentation. We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 150,000 retail customers. Minnesota Power also has 15 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 4. Regulatory Matters.)

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in seven states, more than 1,300 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 200 MW of wind energy facilities under contract to be sold to others. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

U.S. Water Services provided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. In March 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd.

Corporate and Other is comprised of BNI Energy, our coal mining operations in North Dakota; our investment in Nobles 2, an entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota; South Shore Energy, our non-rate regulated, Wisconsin subsidiary developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility; ALLETE Properties, our legacy Florida real estate investment; other business development and corporate expenditures; unallocated interest expense; a small amount of non-rate base generation; approximately 4,000 acres of land in Minnesota; and earnings on cash and investments.

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Overview (Continued)

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2021, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

2021 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2021 to the year ended December 31, 2020. The trends and results for the year ended December 31, 2021 may not be indicative of future results due to uncertainty regarding the COVID-19 pandemic. (See Overview.)

Net income attributable to ALLETE in 2021 was $169.2 million, or $3.23 per diluted share, compared to $174.2 million, or $3.35 per diluted share, in 2020. Net income in 2021 included South Shore Energy’s sale of a portion of its interest in NTEC to Basin Electric Cooperative. The closing of the transaction between South Shore Energy and Basin resulted in the recognition of an approximately $8.5 million after-tax gain, or $0.16 per share, related to prior development costs and risks incurred. Net income in 2021 also included an approximately $5 million after-tax, or $0.10 per share, negative impact related to ALLETE Clean Energy’s Diamond Spring wind energy facility due to an extreme winter storm event in the southwest United States in February 2021. This winter storm event caused volatility in power prices in the regional power market resulting in losses being incurred under one of the facility’s power sales agreements during portions of the winter storm event. Additionally, net income in 2021 included a $3.6 million after-tax, or $0.07 per share, charge resulting from the MPUC’s decision to order refunds in Minnesota Power’s fuel adjustment clause filing covering the period July 2018 through December 2019. Net income in 2020 included margins of $10.2 million after-tax, or $0.20 per share, in Regulated Operations for sales under a 100 MW PSA which expired in April 2020. Net income in 2020 also included reserves for interim rates of $8.3 million after-tax, or $0.16 per share, for the refund of interim rates collected between January 1, 2020, and April 30, 2020. Earnings per share dilution in 2021 was $0.03 due to additional shares of common stock outstanding as of December 31, 2021.

Regulated Operations net income attributable to ALLETE was $129.1 million in 2021, compared to $136.3 million in 2020. Net income at Minnesota Power was lower than 2020 primarily due to: lower margins from Other Power Suppliers resulting primarily from the expiration of a PSA; higher operating and maintenance, property tax and depreciation expenses; and a reserve for refunds resulting from the MPUC’s decision to order refunds in Minnesota Power’s fuel adjustment clause filing covering the period July 2018 through December 2019. These negative impacts were partially offset by increased earnings related to the GNTL; and higher kWh sales to retail and municipal customers. Net income in 2020 also included reserves for interim rates of $8.3 million after-tax for the refund of interim rates collected between January 1, 2020, and April 30, 2020. Net income at SWL&P was lower than 2020 primarily due to higher operating expenses. Our after-tax equity earnings in ATC were lower compared to 2020 primarily due to period over period changes in ATC’s estimate of a refund liability related to the FERC decision on MISO return on equity complaints in 2020.

ALLETE Clean Energy net income attributable to ALLETE was $26.3 million in 2021 compared to $29.9 million in 2020. Net income in 2021 included an approximately $5 million after-tax negative impact related to ALLETE Clean Energy’s Diamond Spring wind energy facility due to an extreme winter storm event in the southwest United States in February 2021 as well as lower wind resources at other wind energy facilities. These negative impacts were partially offset by expense management efforts.

Corporate and Other net income attributable to ALLETE was $13.8 million in 2021 compared to $8.0 million in 2020. Net income in 2021 included South Shore Energy’s sale of a portion of its interest in NTEC to Basin Electric Cooperative which resulted in the recognition of an approximately $8.5 million after-tax gain related to prior development costs and risks incurred, higher earnings from our investment in Nobles 2 which commenced operations in December 2020 and higher land sales at ALLETE Properties. These increases were partially offset by higher expenses.

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2021 Compared to 2020

(See Note 13. Business Segments for financial results by segment.)

Regulated Operations

Year Ended December 31	2021	2020
Millions
Operating Revenue – Utility	$1,227.9	$987.3
Fuel, Purchased Power and Gas – Utility	562.4	358.6
Transmission Services – Utility	75.3	67.0
Operating and Maintenance	216.0	200.9
Depreciation and Amortization	170.7	166.9
Taxes Other than Income Taxes	60.9	50.7
Operating Income	142.6	143.2
Interest Expense	(57.3)	(58.5)
Equity Earnings	21.3	22.3
Other Income	5.9	9.9
Income Before Income Taxes	112.5	116.9
Income Tax Benefit	(16.6)	(19.4)
Net Income Attributable to ALLETE	$129.1	$136.3

Operating Revenue – Utility increased $240.6 million from 2020 primarily due to higher fuel adjustment clause recoveries, higher kWh sales, increased transmission-related revenue related to the GNTL, higher cost recovery rider revenue and higher FERC formula-based rates. Revenue in 2020 also included reserves for the refund of interim rates collected between January 1, 2020, and April 30, 2020.

Fuel adjustment clause revenue increased $121.3 million due to higher fuel and purchased power costs attributable to retail and municipal customers. (See Fuel, Purchased Power and Gas – Utility.) These increases were partially offset by a $5 million charge resulting from the MPUC’s decision to order refunds in Minnesota Power’s fuel adjustment clause filing covering the period July 2018 through December 2019. (See Note 4. Regulatory Matters.)

Revenue from kWh sales increased $67.6 million from 2020 primarily due to higher sales to commercial and industrial customers as well as other power suppliers. These increases were partially offset by lower revenue related to the expiration of a 100 MW PSA in April 2020. Sales to commercial and industrial customers increased primarily due to improving business conditions related to the COVID-19 pandemic and its impact on customer operations. Many commercial and industrial customers operated at reduced levels or were temporarily closed or idled during 2020 as a result of the COVID-19 pandemic and related governmental responses while business conditions improved in 2021. These higher sales to commercial and industrial customers were partially offset by lower sales to and demand revenue from Verso Corporation which indefinitely idled its paper mill in Duluth, Minnesota in 2020. (See Outlook – Regulated Operations – Industrial Customers and Prospective Additional Load.) Sales to other power suppliers, which are sold at market-based prices into the MISO market on a daily basis or through PSAs of various durations, increased primarily due to additional kWh sales made to mitigate the uncertainty of customers’ energy needs and potential load loss due to the COVID-19 pandemic.

Kilowatt-hours Sold	2021	2020	Quantity Variance	% Variance
Millions
Regulated Utility
Retail and Municipal
Residential	1,135	1,134	1	0.1
Commercial	1,359	1,306	53	4.1
Industrial	7,196	6,192	1,004	16.2
Municipal	590	584	6	1.0
Total Retail and Municipal	10,280	9,216	1,064	11.5
Other Power Suppliers	5,102	4,039	1,063	26.3
Total Regulated Utility Kilowatt-hours Sold	15,382	13,255	2,127	16.0

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2021 Compared to 2020 (Continued)

Regulated Operations (Continued)

Revenue from electric sales to taconite customers accounted for 33 percent of regulated operating revenue in 2021 (30 percent in 2020). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of regulated operating revenue in 2021 (5 percent in 2020). Revenue from electric sales to pipelines and other industrial customers accounted for 9 percent of regulated operating revenue in 2021 (9 percent in 2020).

Transmission-related revenue increased $17.7 million primarily due to recovery of GNTL expenses resulting from the GNTL being placed into service in June 2020.

Revenue in 2020 included reserves of $11.7 million for the refund of interim rates collected between January 1, 2020, and April 30, 2020. (See Note 2. Regulatory Matters.)

Cost recovery rider revenue increased $9.0 million primarily due to fewer production tax credits recognized by Minnesota Power. If production tax credits are recognized at a level below those assumed in Minnesota Power’s base rates, an increase in cost recovery rider revenue is recognized to offset the impact of lower production tax credits on income tax expense.

Revenue from wholesale customers under FERC formula-based rates increased $5.2 million primarily due to higher rates.

Operating Expenses increased $241.2 million, or 29 percent, from 2020.

Fuel, Purchased Power and Gas – Utility expense increased $203.8 million, or 57 percent, from 2020 primarily due to higher purchased power prices, kWh sales and fuel costs. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.

Transmission Services – Utility expense increased $8.3 million, or 12 percent, from 2020 primarily due to higher MISO-related expense.

Operating and Maintenance expense increased $15.1 million, or 8 percent, from 2020 primarily due to an increase in contract and professional services and materials purchased for generation facilities and higher vegetation management expenses. In addition, 2021 included higher labor and benefit expenses as compared to 2020.

Depreciation and Amortization expense increased $3.8 million, or 2 percent, from 2020 primarily due to additional property, plant and equipment in service resulting from the GNTL being placed into service in June 2020.

Taxes Other than Income Taxes increased $10.2 million, or 20 percent, from 2020 primarily due to higher property tax expense resulting from the GNTL being placed into service in June 2020 as well as higher estimated taxable market values.

Other Income decreased $4.0 million from 2020 primarily due to lower pension and other postretirement plan non-service credits. (See Note 1. Operations and Significant Accounting Policies.)

Income Tax Benefit decreased $2.8 million from 2020 primarily due to fewer production tax credits in 2021 compared to 2020, partially offset by lower pre-tax income.

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2021 Compared to 2020 (Continued)

ALLETE Clean Energy

Year Ended December 31	2021	2020
Millions
Operating Revenue
Contracts with Customers – Non-utility	$75.5	$68.3
Other – Non-utility (a)	11.4	11.3
Cost of Sales – Non-utility	3.0	—
Operating and Maintenance	41.5	37.4
Depreciation and Amortization	49.2	37.9
Taxes Other than Income Taxes	7.1	3.3
Operating Income	(13.9)	1.0
Interest Expense	(1.5)	(2.2)
Other Income	0.3	0.2
Loss Before Income Taxes	(15.1)	(1.0)
Income Tax Benefit	(16.6)	(19.1)
Net Income	1.5	18.1
Net Loss Attributable to Non-Controlling Interest (b)	(24.8)	(11.8)
Net Income Attributable to ALLETE	$26.3	$29.9

(a)Represents non-cash amortization of differences between contract prices and estimated market prices on assumed PSAs.

(b)See Note 1. Operations and Significant Accounting Policies.

Operating Revenue increased $7.3 million from 2020 primarily due to revenue from the South Peak and Diamond Spring wind energy facilities which commenced operations in April 2020 and December 2020, respectively, partially offset by the negative impact related to ALLETE Clean Energy’s Diamond Spring wind energy facility due to an extreme winter storm event in the southwest United States in February 2021.

	Year Ended December 31,
	2021		2020
Production and Operating Revenue	kWh	Revenue	kWh	Revenue
Millions
Wind Energy Regions
East	236.6	$21.4	262.2	$23.5
Midwest	882.9	32.2	902.0	32.2
South	1,009.8	11.2	169.1	3.9
West	823.2	22.1	777.5	20.0
Total Production and Operating Revenue	2,952.5	$86.9	2,110.8	$79.6

Cost of Sales increased $3.0 million from 2020 due to a reserve for an anticipated loss on sale of ALLETE Clean Energy’s project to repower and sell its Northern Wind project. (See Outlook – ALLETE Clean Energy.)

Operating and Maintenance expense increased $4.1 million, or 11 percent, from 2020 primarily due to operating and maintenance expenses related to the South Peak and Diamond Spring wind energy facilities as well as expense related to the Caddo wind energy facility which commenced operations in December 2021. These increases were offset by expense management efforts.

Depreciation and Amortization expense increased $11.3 million, or 30 percent, from 2020 primarily due to additional property, plant and equipment in service related to the South Peak and Diamond Spring wind energy facilities.

Taxes Other Than Income Taxes increased $3.8 million from 2020 primarily due to higher property tax expense related to the Diamond Spring wind energy facility.

Income Tax Benefit decreased $2.5 million from 2020 primarily due to less production tax credits generated in 2021.

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2021 Compared to 2020 (Continued)

ALLETE Clean Energy (Continued)

Net Loss Attributable to Non-Controlling Interest increased $13.0 million from 2020 primarily due to net losses attributable to non-controlling interest for the Diamond Spring wind energy facility.

Corporate and Other

Operating Revenue increased $2.2 million, or 2 percent, from 2020 primarily due to higher land sales at ALLETE Properties in 2021, partially offset by lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses and fewer tons sold in 2021 compared to 2020.

Net Income Attributable to ALLETE was $13.8 million in 2021 compared to $8.0 million in 2020. Net income in 2021 included South Shore Energy’s sale of a portion of its interest in NTEC to Basin Electric Cooperative which resulted in the recognition of an approximately $8.5 million after-tax gain related to prior development costs and risks incurred, higher earnings from our investment in Nobles 2 which commenced operations in December 2020 and higher land sales at ALLETE Properties. These increases were partially offset by higher expenses. Net income at BNI Energy was $7.5 million in 2021 compared to net income of $7.3 million in 2020. Net income at ALLETE Properties was $1.9 million in 2021 compared to net income of $0.4 million in 2020.

Income Taxes – Consolidated

For the year ended December 31, 2021, the effective tax rate was a benefit of 24.3 percent (benefit of 32.4 percent for the year ended December 31, 2020). The effective tax rate for 2021 was a lower benefit primarily due to fewer production tax credits generated in 2021. (See Note 10. Income Tax Expense.)

2020 Compared to 2019

The comparison of the results of operations for the years ended December 31, 2020 and 2019 is included in Management's Discussion in the Annual Report on Form 10-K for the year ended December 31, 2020.

Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires management to make various estimates and assumptions that affect amounts reported in the Consolidated Financial Statements. These estimates and assumptions may be revised, which may have a material effect on the Consolidated Financial Statements. Actual results may differ from these estimates and assumptions. These policies are discussed with the Audit Committee of our Board of Directors on a regular basis. We believe the following policies are most critical to our business and the understanding of our results of operations.

Regulatory Accounting. Our regulated utility operations are subject to accounting standards for the effects of certain types of regulation. These standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income. (See Note 4. Regulatory Matters.)

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Critical Accounting Policies (Continued)

Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and other postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of several important assumptions, including the expected long-term rate of return on plan assets, the discount rate and mortality assumptions, among others, in determining our obligations and the annual cost of our pension and other postretirement benefits. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class and adjust these for current economic conditions while utilizing the target allocation of our plan assets to forecast the expected long-term rate of return. Our pension asset allocation as of December 31, 2021, was approximately 49 percent equity securities, 48 percent fixed income and 3 percent real estate. Our postretirement health and life asset allocation as of December 31, 2021, was approximately 70 percent equity securities, 29 percent fixed income and 1 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2021, we used weighted average expected long-term rates of return of 6.50 percent in our actuarial determination of our pension expense and 5.85 percent in our actuarial determination of our other postretirement expense. The actuarial determination uses an asset smoothing methodology for actual returns to reduce the volatility of varying investment performance over time. We review our expected long-term rate of return assumption annually and will adjust it to respond to changing market conditions. A one-quarter percent decrease in the expected long-term rate of return would increase the annual expense for pension and other postretirement benefits by approximately $2.0 million, pre-tax.

The discount rate is computed using a bond matching study which utilizes a portfolio of high quality bonds that produce cash flows similar to the projected costs of our pension and other postretirement plans. In 2021, we used weighted average discount rates of 2.87 percent and 2.70 percent in our actuarial determination of our pension and other postretirement expense, respectively. We review our discount rates annually and will adjust them to respond to changing market conditions. A one-quarter percent decrease in the discount rate would increase the annual expense for pension and other postretirement benefits by approximately $1.7 million, pre-tax.

The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2021, considered a modified PRI-2012 mortality table and MP-2021 mortality projection scale. (See Note 11. Pension and Other Postretirement Benefit Plans.)

Impairment of Long-Lived Assets. We review our long-lived assets for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our long‑lived assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to maintain the operations.

Taxation. We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income taxes and taxes other than income taxes. Judgments related to income taxes require the recognition in our financial statements of the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit. Tax positions that do not meet the “more-likely-than-not” criteria are reflected as a tax liability in accordance with the accounting standards for uncertainty in income taxes. We record a valuation allowance against our deferred tax assets to the extent it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

We are subject to income taxes in various jurisdictions. We make assumptions and judgments each reporting period to estimate our income tax assets, liabilities, benefits and expenses. Judgments and assumptions are supported by historical data and reasonable projections. Our assumptions and judgments include the application of tax statutes and regulations, and projections of future federal taxable income, state taxable income, and state apportionment to determine our ability to utilize NOL and credit carryforwards prior to their expiration. Significant changes in assumptions regarding future federal and state taxable income or a change in tax rates could require new or increased valuation allowances which could result in a material impact on our results of operations.

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Outlook

ALLETE is an energy company committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses, and sustains growth. The Company has a long-term objective of achieving consolidated average annual earnings per share growth within a range of 5 percent to 7 percent.

ALLETE is predominately a regulated utility through Minnesota Power, SWL&P, and an investment in ATC. ALLETE’s strategy is to remain predominately a regulated utility while investing in ALLETE Clean Energy and its Corporate and Other businesses to complement its regulated businesses, balance exposure to the utility’s industrial customers, and provide potential long-term earnings growth. ALLETE expects net income from Regulated Operations to be approximately 75 percent of total consolidated net income in 2022. Over the next several years, the contribution of ALLETE Clean Energy and our Corporate and Other businesses to net income is expected to increase as ALLETE grows these operations. ALLETE expects its businesses to provide regulated, contracted or recurring revenues, and to support sustained growth in net income and cash flow.

Regulated Operations. Minnesota Power’s long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable energy requirements. Keeping the cost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain customer viability. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. Minnesota Power has a goal of delivering 100 percent carbon-free energy by 2050. (See EnergyForward.) We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approvals for transmission, renewable and environmental investments, as well as work with regulators to earn a fair rate of return.

Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, FERC, PSCW and NDPSC. See Note 4. Regulatory Matters for discussion of regulatory matters within these jurisdictions.

2022 Minnesota General Rate Case. On November 1, 2021, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 18 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $108 million in additional revenue. In orders dated December 30, 2021, the MPUC accepted the filing as complete and authorized an annual interim rate increase beginning January 1, 2022, with approximately $80 million expected to be collected in cash and approximately $8 million of interim rates for residential customers deferred with a final determination on recovery at the end of the rate case.

Minnesota Power Land Sales. In August 2020, Minnesota Power filed a petition with the MPUC for approval to sell land that surrounds several reservoirs on its hydroelectric system and is no longer required to maintain its operations. The land has an estimated value of approximately $100 million, and Minnesota Power proposed to credit ratepayers the net proceeds from the sales in a future rate case or through its renewable resources rider to mitigate future rate increases. In an order dated November 18, 2021, the MPUC authorized the land sales and directed the net proceeds to be refunded to ratepayers subject to certain conditions and required compliance filings.

Wisconsin General Rate Case. SWL&P expects to file its next general rate case in 2022. The PSCW granted an extension request made by SWL&P to delay filing its next general rate case until on or before December 20, 2022. SWL&P requested the extension primarily due to impacts of the COVID-19 pandemic.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load

Industrial Customers. Electric power is one of several key inputs in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Approximately 47 percent of our regulated utility kWh sales in 2021 (47 percent in 2020 and 54 percent in 2019) were made to our industrial customers. We expect industrial sales of approximately 6.5 million MWh in 2022 (7.2 million MWh in 2021 and 6.2 million in 2020). (See Item 1. Business – Regulated Operations – Electric Sales / Customers.)

Taconite. Minnesota Power’s taconite customers are capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry, which continue to lead the world in environmental performance among steelmaking countries. According to the U.S. Department of Energy, steel production in the U.S. is the most energy efficient of any major steel producing country. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, tubular applications for all industries, and in the construction industry. Steel is also a critical component of the clean energy transformation underway today. Meeting the demand for more renewable energy and the need for additional infrastructure to transport green energy from the point of generation to the end user both require steel. Historically, less than 10 percent of Minnesota taconite production has been exported outside of North America.

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 82 percent of capacity in 2021 (68 percent in 2020 and 80 percent in 2019). The World Steel Association, an association of steel producers, national and regional steel industry associations, and steel research institutes representing approximately 85 percent of world steel production, projected U.S. steel consumption in 2022 will increase by approximately 6 percent compared to 2021.

Minnesota Power’s taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We expect taconite production from our taconite customers of approximately 35 million tons in 2022. We estimate that a one million ton change in Minnesota Power’s taconite customers’ production would impact our annual earnings per share by approximately $0.04, net of expected power marketing sales at current prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Minnesota Power proactively sells power in the wholesale power markets that is temporarily not required by industrial customers to optimize the value of its generating facilities. Long-term reductions in taconite production or a permanent shut down of a taconite customer may lead Minnesota Power to file a general rate case to recover lost revenue.

USS Corporation. In April 2020, USS Corporation stated it would idle its Keetac facility in Keewatin, Minnesota, in response to the sudden and dramatic decline in business conditions resulting from the COVID-19 pandemic. In addition, in May 2020, USS Corporation announced that production was expected to be temporarily reduced at its Minntac Plant in Mountain Iron, Minnesota. USS Corporation resumed normal production at its Minntac Plant beginning in late July 2020 and resumed operations at its Keetac facility in December 2020. In October 2021, USS Corporation announced that it will be increasing its blast furnace operating rates at its Gary, Indiana steel mill through the installation of a 500,000 ton per year pig iron caster. When completed in early 2023, the pig iron produced from Minnesota iron ore would be used at USS Corporation’s Big River steel making facility in Osceola, Arkansas. USS Corporation has the capability to produce approximately 15 million and 5 million tons annually at its Minntac and Keetac plants, respectively.

Cliffs. In December 2020, Cliffs announced that it had completed the previously announced acquisition of substantially all of the operations of ArcelorMittal USA LLC and its subsidiaries. Cliffs had stated that upon closure of the acquisition Cliffs would be the largest flat-rolled steel producer and the largest iron ore pellet producer in North America. The acquisition included ArcelorMittal’s Minorca mine in Virginia, Minnesota, and its ownership share of Hibbing Taconite in Hibbing, Minnesota, which are both large industrial customers of Minnesota Power. Cliffs is now Minnesota Power’s largest customer. The acquisition has increased customer concentration risk for the Company and could lead to further capacity consolidation for both steel blast furnaces and the related Minnesota iron ore production.

Cliffs completed construction of a hot briquetted iron production plant in Toledo, Ohio, in 2020, which has utilized direct reduced-grade pellets from Northshore Mining. In October 2021, Cliffs indicated it plans to move direct reduced-grade pellet production to its Minorca mine and that Northshore Mining would become a “swing facility” due to the higher royalty rates at that mine. (See Northshore Mining.).

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

Northshore Mining. In April 2020, Cliffs announced that, based on market conditions, it would be temporarily idling Northshore Mining. Cliffs idled production at Northshore Mining in April 2020 and resumed normal production at the facility in August 2020. On February 11, 2022, Cliffs announced that with the use of additional scrap in its basic oxygen furnaces, iron ore needs are not as high as before. When determining where to adjust production, Cliffs decided to idle all production at its Northshore mine. Cliffs anticipated that the Northshore mine will be temporarily idled for approximately four months during 2022. Cliffs also indicated that going forward it will be limiting the tonnage of iron ore pellets sold to third parties. Northshore Mining has the capability to produce approximately 6 million tons annually. Minnesota Power has a PSA through 2031 with Silver Bay Power, which provides the majority of the electric service requirements for Northshore Mining. (See Silver Bay Power and Cliffs.)

Silver Bay Power. In 2016, Minnesota Power and Silver Bay Power entered into a PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which had previously been served predominately through self-generation by Silver Bay Power. Starting in 2016, Minnesota Power supplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power had the option to purchase additional energy from Minnesota Power as it transitioned away from self-generation. In the third quarter of 2019, Silver Bay Power ceased self-generation and Minnesota Power began supplying the full energy requirements for Silver Bay Power.

Hibbing Taconite. In April 2020, ArcelorMittal announced that Hibbing Taconite in Hibbing, Minnesota, would idle production due to the COVID-19 pandemic. Hibbing Taconite resumed normal production in August 2020. Hibbing Taconite’s current mineable ore reserves are expected to be exhausted in 2025. Cliffs, which in December 2020 became majority owner and resumed management of Hibbing Taconite, has stated that it has a plan to extend the mine life of Hibbing Taconite with ore reserves already under control of Cliffs. There are ample ore reserves in northeastern Minnesota that could supply operations for decades to come, and Minnesota Power’s taconite customers routinely develop and extend their mine plans to optimize assets. Hibbing Taconite has the capability to produce approximately 8 million tons annually.

Minnesota Sulfate Wild Rice Water Quality Standard. On April 29, 2021, the EPA identified rivers and lakes in Minnesota in which wild rice grows that have sulfate levels that exceed Minnesota’s sulfate limit for wild rice waters. On September 1, 2021, three additional wild rice waters with sulfate levels that exceed Minnesota’s sulfate limit were identified. The EPA directed the MPCA to add these rivers and lakes to its list of impaired waters which can be used to set limits in discharge permits for industrial activities such as mining. Minnesota Power’s taconite customers could be adversely impacted if they are required to significantly reduce sulfate discharges.

Paper, Pulp and Secondary Wood Products. The North American paper and pulp industry faces declining demand due to the impact of electronic substitution for print and changing customer needs. As a result, certain paper and pulp customers have reduced their existing operations in recent years and have pursued or are pursuing product changes in response to the declining demand. We expect operating levels in 2022 at the major paper and pulp mills we serve to be lower than in 2021 as several customers operated at higher than normal levels in 2021.

Verso Corporation and ST Paper. In June 2020, Verso Corporation indefinitely idled its paper mill in Duluth, Minnesota (Duluth Mill). Verso Corporation stated the decision was due to the accelerated decline in graphic paper demand resulting from the COVID-19 pandemic and has disclosed it is considering options for the Duluth Mill, including marketing for a sale. On January 29, 2021, Verso Corporation provided notice of termination for its contract. Minnesota Power and Verso Corporation mutually agreed to resolve the outstanding commitments under the contract in January 2022. In May 2021, Verso Corporation announced the completion of the sale of the Duluth Mill to ST Paper LLC (ST Paper). ST Paper has stated it plans to convert the Duluth Mill to produce tissue. In January 2022, Minnesota Power entered into an electric service agreement with ST Paper, subject to MPUC approval, that would begin Large Power customer service with a minimum term of 6-years upon start-up of operations, which is anticipated in 2023. The agreement will qualify as a Large Power customer contract as we expect to serve requirements of at least 10 MW of customer load.

Pipeline and Other Industries.

Cenovus Energy. In 2018, a fire at Cenovus Energy’s refinery in Superior, Wisconsin, which was owned by Husky Energy at that time, disrupted operations at the facility. Under normal operating conditions, SWL&P provides approximately 14 MW of average monthly demand to the refinery in addition to water service. The facility remains at minimal operations, and the refinery is not expected to resume normal operations until 2023.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

Prospective Additional Load. Minnesota Power is pursuing new wholesale and retail loads in and around its service territory. Currently, several companies in northeastern Minnesota continue to progress in the development of natural resource-based projects that represent long-term growth potential and load diversity for Minnesota Power. We cannot predict the outcome of these projects.

PolyMet. PolyMet is planning to start a new copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. In 2015, PolyMet announced the completion of the final EIS by state and federal agencies, which was subsequently published in the Federal Register and Minnesota Environmental Quality Board Monitor. The Minnesota Department of Natural Resources (DNR) and the U.S. Army Corps of Engineers have both issued final Records of Decision, finding the final EIS adequate.

PolyMet was issued all necessary permits to construct and operate its new mining operation; however, of the more than 20 permits issued to build and operate the mine, three permits remain on hold pending legal or regulatory action, which is expected to continue during 2022. Minnesota Power could supply between 45 MW and 50 MW of load under a 10-year power supply contract with PolyMet that would begin upon start-up of operations.

EnergyForward. Minnesota Power is executing EnergyForward, its strategy assuring reliability, protecting affordability and further improving environmental performance. The plan includes completed and planned investments in wind, solar, natural gas and hydroelectric power, construction of additional transmission capacity, the installation of emissions control technology and the idling and retirement of certain coal-fired generating facilities. Minnesota Power has a vision to deliver 100 percent carbon-free energy to customers by 2050, continuing its commitment to climate, customers and communities through its EnergyForward strategy. This vision builds on Minnesota Power’s recent achievement of now providing 50 percent renewable energy to its customers.

2021 Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP with the MPUC, which outlines its clean-energy transition plans through 2035. These plans include expanding its renewable energy supply to 70 percent by 2030, achieving coal-free operations at its facilities by 2035, and investing in a resilient and flexible transmission and distribution grid. Minnesota Power has also set a target to achieve an 80 percent reduction in carbon emissions by 2035 compared to 2005 levels. As part of these plans, Minnesota Power anticipates adding approximately 400 MW of new wind and solar energy resources, retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Minnesota Power’s plans recognize that advances in technology will play a significant role in completing its transition to carbon-free energy supply, reliably and affordably. A final decision on the IRP is expected in the second half of 2022.

In recent years, Minnesota Power has transformed its energy supply from more than a 95 percent reliance on coal to become a leader in the nation’s clean-energy transformation. Since 2013, the company has closed or converted seven of its nine coal-fired units and added nearly 900 megawatts of renewable energy sources. Additionally, Minnesota Power has been a leader in energy conservation, surpassing the state’s conservation goals each year for the past decade.

Nemadji Trail Energy Center. In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of a natural gas capacity dedication and other affiliated-interest agreements for NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to the capacity dedication agreement.

Renewable Energy. Minnesota Power continues to execute its renewable energy strategy and recently reached its goal of supplying 50 percent of its energy by renewable energy sources. Minnesota Power also has a goal of delivering 100 percent carbon-free energy by 2050. (See EnergyForward.)

Minnesota Power has approved cost recovery riders for certain renewable investments and expenditures as well as investments and expenditures related to compliance with the Minnesota Solar Energy Standard. The cost recovery riders allow Minnesota Power to charge retail customers on a current basis for the costs of certain renewable and solar investments and expenditures plus a return on the capital invested. (See Note 4. Regulatory Matters.)

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Outlook (Continued)

EnergyForward (Continued)

Wind Energy. Minnesota Power’s wind energy facilities consist of Bison (497 MW) located in North Dakota, and Taconite Ridge (25 MW) located in northeastern Minnesota. Minnesota Power also has two long-term wind energy PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) located in North Dakota.

Minnesota Power uses the 465-mile, 250-kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota, to transport wind energy from North Dakota while gradually phasing out coal-based electricity delivered to its system over this transmission line from Square Butte’s lignite coal-fired generating unit. Minnesota Power is currently pursuing a modernization and capacity upgrade of its DC transmission system to continue providing reliable operations and additional system capabilities.

Nobles 2 PPA. Minnesota Power has a long-term PPA with Nobles 2 that provides for Minnesota Power to purchase the energy and associated capacity from a 250 MW wind energy facility in southwestern Minnesota through 2040. The agreement provides for the purchase of output from the facility at fixed energy prices. There are no fixed capacity charges, and Minnesota Power will only pay for energy as it is delivered. (See Corporate and Other – Investment in Nobles 2.)

Manitoba Hydro. Minnesota Power has three long-term PPAs with Manitoba Hydro. Under the first PPA, Minnesota Power is purchasing surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term. The second PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro through May 2035. The third PPA provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro through June 2040. (See Note 8. Commitments, Guarantees and Contingencies.)

Solar Energy. Minnesota Power’s solar energy supply consists of Camp Ripley, a 10 MW solar energy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, and a community solar garden in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. SWL&P also plans to construct a 470 kW solar array in 2022 as part of a community solar garden in Superior, Wisconsin, which was approved by the PSCW in October 2020.

In June 2020, Minnesota Power filed a proposal with the MPUC to accelerate its plans for purchasing solar energy from approximately 20 MW of solar energy projects in Minnesota which was approved in a June 2021 order. These solar energy projects will be constructed and owned through an ALLETE subsidiary with an estimated investment of $40 million. Construction of these solar energy projects is expected to commence in 2022.

Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others) and our investment in ATC. See Item 1. Business – Regulated Operations and Note 8. Commitments, Guarantees and Contingencies.

Duluth Loop Reliability Project. On October 21, 2021, Minnesota Power submitted an application for a certificate of need for the Duluth Loop Reliability Project. This transmission project was proposed to enhance reliability in and around Duluth, Minnesota. The project includes the construction of a new 115-kV transmission line; construction of an approximately one-mile extension of an existing 230-kV transmission line; and upgrades to several substations. The Duluth Loop Reliability Project is expected to be completed and in service by 2025, subject to MPUC approval, with an estimated cost of $50 million to $70 million.

ALLETE Clean Energy.

ALLETE Clean Energy will pursue growth through acquisitions or project development. ALLETE Clean Energy is targeting acquisitions of existing operating portfolios which have a mix of long-term PSAs in place and/or available for repowering and recontracting. Further, ALLETE Clean Energy will evaluate actions that will lead to the addition of complimentary clean energy products and services. At this time, ALLETE Clean Energy expects acquisitions or development of new facilities will be primarily wind, solar, energy storage or storage ready facilities across North America. ALLETE Clean Energy is also targeting the development of new facilities up to 300 MW each, which will have long-term PSAs in place for the output or may be sold upon completion.

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Outlook (Continued)

ALLETE Clean Energy (Continued)

Portions of our ALLETE Clean Energy business are experiencing return pressures that are impacting our earnings per share growth from increased competition, and lower forward price curves, as a growing amount of investment capital is being directed into wind generation opportunities. In addition, current and potential new project developments can be negatively affected by a lower ALLETE stock price, which may result in such projects not being accretive, or otherwise unable to satisfy our financial objectives criteria to proceed. In response to these market pressures, we are actively evaluating additional growth opportunities to deliver more comprehensive clean energy solutions for customers at ALLETE Clean Energy, which may include solar, storage solutions, and related energy infrastructure investments and services. We believe that the renewable energy industry is entering a new phase of growth and that we are well-positioned to serve customers and drive future growth at ALLETE. ALLETE Clean Energy will continue to optimize its existing wind energy facility portfolio, seek development of its remaining safe harbor inventory of tax credit qualified turbines, and explore other renewable energy opportunities to expand its service offerings to further enhance its growth and profitability.

Federal production tax credit qualification is important to the economics of project development, and ALLETE Clean Energy has invested in equipment to meet production tax credit safe harbor provisions which provides an opportunity to seek development of its remaining safe harbor production tax credit qualified equipment through 2025 based on the most recent PTC safe harbor extension by the IRS. ALLETE Clean Energy has completed its investment of approximately $80 million for production tax credit requalification of approximately 470 WTGs at its Storm Lake I, Storm Lake II, Lake Benton and Condon wind energy facilities. We anticipate annual production tax credits relating to these projects of approximately $17 million to $22 million annually through 2027 and decreasing thereafter through 2030. Disruptions in our supply chains or a lack of available financing resulting from the ongoing COVID-19 pandemic, if they occur, could jeopardize our ability to complete certain capital projects in time to qualify them for production tax credits. To date we have not experienced disruptions in our supply chains related to the COVID-19 pandemic.

In March 2020, ALLETE Clean Energy acquired the rights to the approximately 300 MW Caddo wind development project in Oklahoma from Apex Clean Energy. The Caddo wind project is fully contracted to sell wind power under long-term power sales agreements; construction was completed and tax equity funding of $62.0 million of cash, net of issuance costs, was received in the fourth quarter of 2021 with an additional $183.0 million of cash, net of issuance costs, received in January 2022. Also in January 2022, ALLETE Clean Energy acquired a portion of the non-controlling interest for its Caddo wind energy facility for approximately $30 million.

On February 4, 2021, ALLETE Clean Energy entered into a purchase and sale agreement with a subsidiary of Xcel Energy Inc. to sell a 100 MW wind energy facility for approximately $185 million. ALLETE Clean Energy will repower its Northern Wind project, consisting of its 98 MW Chanarambie and Viking wind energy facilities located in southwest Minnesota, as part of the transaction. Construction is expected to begin in 2022 with the Northern Wind project expected to continue operating until the second quarter of 2022. At a hearing in June 2021, the MPUC approved the sale, which is expected to close in late 2022, subject to completion of construction and receipt of permits. ALLETE Clean Energy has experienced inflationary increases and significant cost pressures related to this project and as a result now anticipates a loss on sale of the project, which resulted in an approximately $2 million after-tax charge in the fourth quarter of 2021.

In May 2021, ALLETE Clean Energy announced that it acquired the rights to the approximately 92 MW Red Barn wind development project and the approximately 68 MW Whitetail renewable development project in southwestern Wisconsin. ALLETE Clean Energy also signed an asset sale agreement for the completed Red Barn wind project with Wisconsin Public Service Corporation and Madison Gas and Electric Company. At a hearing in January 2022, the PSCW approved the sale of the Red Barn wind project, which is expected to close in 2023, subject to completion of construction and receipt of permits.

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Outlook (Continued)

ALLETE Clean Energy (Continued)

ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current operating portfolio is subject to typical variations in seasonal wind with higher wind resources typically available in the winter months. The majority of its planned maintenance leverages this seasonality and is performed during lower wind periods. ALLETE Clean Energy’s current operating portfolio is as follows:

Region	Wind Energy Facility	Capacity MW	PSA MW	PSA Expiration
East	Armenia Mountain	101	100%	2024
Midwest	Chanarambie/Viking	98
	PSA 1 (a)		12%	2023
	PSA 2		88%	2023
	Lake Benton	104	100%	2028
	Storm Lake I	108	100%	2027
	Storm Lake II	77
	PSA 1		90%	2022
	PSA 2		10%	2032
	Other	17	100%	2028
South	Caddo	303
	PSA 1		26%	2034
	PSA 2		66%	2034
	PSA 3		7%	2034
	Diamond Spring	303
	PSA 1		58%	2035
	PSA 2		25%	2032
	PSA 3		16%	2035
West	Condon	50	100%	2022
	Glen Ullin	106	100%	2039
	South Peak	80	100%	2035

(a)The PSA expiration assumes the exercise of four one-year renewal options that ALLETE Clean Energy has the sole right to exercise.

Non-cash amortization to revenue recognized by ALLETE Clean Energy relates to the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of wind energy facility acquisitions, ALLETE Clean Energy assumed various PSAs that were above or below estimated market prices at the time of acquisition; the resulting differences between contract prices and estimated market prices are amortized to revenue over the remaining PSA term. Non-cash amortization is expected to be approximately $7 million in 2022, $5 million in 2023, $6 million annually in 2024 through 2027, and decreasing thereafter through 2032.

Corporate and Other.

BNI Energy. In 2021, BNI Energy sold 3.9 million tons of coal (4.2 million tons in 2020) and anticipates 2022 sales will be similar to 2021. BNI Energy operates under cost-plus fixed fee agreements extending through December 31, 2037.

Investment in Nobles 2. Our subsidiary, ALLETE South Wind, owns a 49 percent equity interest in Nobles 2, the entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. We account for our investment in Nobles 2 under the equity method of accounting. (See Note 5. Equity Investments.)

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Outlook (Continued)

Corporate and Other (Continued)

South Shore Energy. South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary, is developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to a capacity dedication agreement. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $700 million, of which South Shore Energy’s portion is expected to be approximately $150 million. South Shore Energy’s portion of NTEC project costs incurred through December 31, 2021, is approximately $5 million.

On October 1, 2021, South Shore Energy sold a portion of its undivided ownership interest in NTEC for approximately $20 million representing reimbursement of current costs plus a fee for prior development costs and risks incurred. Following the transaction, South Shore Energy now owns a 20 percent undivided ownership interest in NTEC, Basin owns a 30 percent undivided ownership interest in NTEC and Dairyland Power Cooperative continues to own a 50 percent undivided ownership interest in NTEC. The closing of the transaction resulted in the recognition of an approximately $8.5 million after-tax gain recorded in Corporate and Other in the fourth quarter of 2021, related to prior development costs and risks incurred.

ALLETE Properties. Our strategy incorporates the possibility of a bulk sale of the entire ALLETE Properties portfolio. Proceeds from a bulk sale would be strategically deployed to support growth initiatives at our Regulated Operations and ALLETE Clean Energy. ALLETE Properties also continues to pursue sales of individual parcels over time and will continue to maintain key entitlements and infrastructure.

Income Taxes

ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 28 percent for 2021. ALLETE also has tax credits and other tax adjustments that reduce the combined statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as production tax credits, excess deferred taxes, non-controlling interests in subsidiaries, as well as other items. The annual effective rate can also be impacted by such items as changes in income before income taxes, state and federal tax law changes that become effective during the year, business combinations, tax planning initiatives and resolution of prior years’ tax matters. We expect our effective tax rate to be a benefit of approximately 5 percent for 2022 primarily due to federal production tax credits as a result of wind energy generation and non-controlling interests in subsidiaries. We also expect that our effective tax rate will be lower than the combined statutory rate over the next 10 years due to production tax credits attributable to our wind energy generation.

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Liquidity and Capital Resources

Liquidity Position. ALLETE is well-positioned to meet its liquidity needs; however, the Company is monitoring capital markets and other financing sources in light of the ongoing COVID-19 pandemic. (See Item 1A. Risk Factors.) A disruption in capital markets could lead to increased borrowing costs or adversely impact our ability to access capital markets or other financing sources. If we are not able to access capital on acceptable terms in sufficient amounts and when needed, or at all, the ability to maintain our businesses or to implement our business plans would be adversely affected.

As of December 31, 2021, we had cash and cash equivalents of $45.1 million, $240.8 million in available consolidated lines of credit, 2.1 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets and a debt-to-capital ratio of 40 percent.

Capital Structure. ALLETE’s capital structure for each of the last three years is as follows:

As of December 31	2021	%	2020	%	2019	%
Millions
ALLETE Equity	$2,413.1	49	$2,294.6	50	$2,231.9	56
Non-Controlling Interest in Subsidiaries	533.2	11	505.6	11	—	3
Short-Term and Long-Term Debt (a)	1,986.4	40	1,806.4	39	1,622.6	41
	$4,932.7	100	$4,606.6	100	$3,958.2	100

(a) Excludes unamortized debt issuance costs.

Cash Flows. Selected information from ALLETE’s Consolidated Statement of Cash Flows is as follows:

Year Ended December 31	2021	2020	2019
Millions
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$65.2	$92.5	$79.0
Cash Flows from (used for)
Operating Activities	263.5	299.8	246.9
Investing Activities	(485.2)	(812.8)	(342.7)
Financing Activities	204.2	485.7	109.3
Change in Cash, Cash Equivalents and Restricted Cash	(17.5)	(27.3)	13.5
Cash, Cash Equivalents and Restricted Cash at End of Period	$47.7	$65.2	$92.5

Operating Activities. Cash from operating activities was lower in 2021 compared to 2020. Cash from operating activities in 2021 included lower net income and higher payments for inventories compared to 2020, and was negatively impacted by the timing of recovery and refund of the fuel adjustment clause.

Cash from operating activities was higher in 2020 compared to 2019. Cash from operating activities in 2019 included the refund of Minnesota Power’s provisions for interim rates and tax reform, and the impact of U.S. Water Services prior to its sale. Cash from operating activities in 2020 included lower collections of accounts receivable due to timing.

Investing Activities. Cash used for investing activities was lower in 2021 compared to 2020. Cash used for investing activities in 2021 reflected lower additions to property, plant and equipment and lower payments for equity method investments compared to 2020.

Cash used for investing activities in 2020 was higher compared to 2019. Cash used for investing activities in 2020 included higher additions to property, plant and equipment and additional payments for equity method investments compared to 2019. Cash used for investing activities in 2019 included proceeds received from the sale of U.S. Water Services.

Financing Activities. Cash from financing activities was lower in 2021 compared to 2020 primarily due to lower proceeds from non-controlling interest in subsidiaries and higher repayments of short-term and long-term debt in 2021. These decreases were partially offset by higher proceeds from the issuance of common stock and higher proceeds from the issuance of short-term and long-term debt in 2021.

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Liquidity and Capital Resources (Continued)

Cash Flows (Continued)

Cash from financing activities was higher in 2020 compared to 2019 primarily due to higher proceeds from the issuance of long-term debt and proceeds from a tax equity financing (non-controlling interest in subsidiaries) in 2020. These increases were partially offset by higher repayments of long-term debt in 2020.

Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit and the issuance of securities, including long-term debt, common stock and commercial paper. As of December 31, 2021, we had consolidated bank lines of credit aggregating $432.0 million ($407.0 million as of December 31, 2020), most of which expire in January 2025. We had $31.5 million outstanding in standby letters of credit and $159.7 million outstanding draws under our lines of credit as of December 31, 2021 ($22.3 million in standby letters of credit and no outstanding draws as of December 31, 2020). We also have other credit facility agreements in place that provide the ability to issue up to $100.0 million in standby letters of credit. As of December 31, 2021, we had $91.2 million outstanding in standby letters of credit under these agreements.

In January 2022, ALLETE Clean Energy received approximately $183.0 million from final closing of tax equity funding for the Caddo wind energy facility. The proceeds from the funding were used to pay down a portion of outstanding draws on our lines of credit.

In addition, as of December 31, 2021, we had 3.1 million original issue shares of our common stock available for issuance through Invest Direct and 2.1 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets. (See Securities.) The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. We entered into a distribution agreement with Lampert Capital Markets, in 2008, as amended most recently in 2020, with respect to the issuance and sale of up to an aggregate of 13.6 million shares of our common stock, without par value, of which 2.1 million shares remain available for issuance as of December 31, 2021. For the year ended December 31, 2021, 0.8 million shares of common stock were issued under this agreement resulting in net proceeds of $51.0 million (none in 2020 and 2019).

During the year ended December 31, 2021, we issued 0.3 million shares of common stock through Invest Direct, the Employee Stock Purchase Plan and the Retirement Savings and Stock Ownership Plan, resulting in net proceeds of $18.9 million (0.4 million shares for net proceeds of $18.1 million in 2020; 0.2 million shares for net proceeds of $1.9 million in 2019). See Note 9. Common Stock and Earnings Per Share for additional detail regarding ALLETE’s equity securities.

Financial Covenants. See Note 7. Short-Term and Long-Term Debt for information regarding our financial covenants.

Pension and Other Postretirement Benefit Plans. Management considers various factors when making funding decisions, such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the defined benefit pension plans. For the year ended December 31, 2021, we contributed $10.3 million in cash to the defined benefit pension plans. We do not expect to make any contributions to our defined benefit pension plans in 2022, and we do not expect to make any contributions to our other postretirement benefit plans in 2022. (See Note 9. Common Stock and Earnings Per Share and Note 11. Pension and Other Postretirement Benefit Plans.)

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 8. Commitments, Guarantees and Contingencies.

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Liquidity and Capital Resources (Continued)

Contractual Obligations and Commercial Commitments. ALLETE has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Material contractual obligations and other commitments are as follows:

Long-Term Debt. ALLETE has material long-term debt obligations, including long-term debt due within one year. These obligations include the principal amount of bonds, notes and loans which are recorded on the Consolidated Balance Sheet, plus interest. (See Note 7. Short-Term and Long‑Term Debt.)

Pension and Other Postretirement Benefit Plans. Pension and other postretirement benefit plan obligations include the current estimate of future benefit payments. Pension contributions are dependent on several factors including realized asset performance, future discount rate and other actuarial assumptions, Internal Revenue Service and other regulatory requirements, and contributions required to avoid benefit restrictions for the pension plans. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements. Our obligations are estimates and will change based on actual market performance, changes in interest rates and any changes in governmental regulations. (See Note 11. Pension and Other Postretirement Benefit Plans.)

Operating Lease Obligations. ALLETE has certain operating lease obligations for the minimum payments required under various lease agreements which are recorded on the Consolidated Balance Sheet. (See Note 1. Operations and Significant Accounting Policies.)

Easement Obligations. ALLETE has easement obligations for the minimum payments required under our land easement agreements at our wind energy facilities. (See Note 8. Commitments, Guarantees and Contingencies.)

PPA Obligations. PPA obligations represent our Square Butte, Manitoba Hydro and other PPAs. (See Note 8. Commitments, Guarantees and Contingencies.)

Other Purchase Obligations. ALLETE has other purchase obligations covering our minimum purchase commitments under coal supply and rail contracts, and long-term service agreements for wind energy facilities. (See Note 8. Commitments, Guarantees and Contingencies.)

Credit Ratings. Access to reasonably priced capital markets is dependent in part on credit and ratings. Our securities have been rated by S&P and by Moody’s. Rating agencies use both quantitative and qualitative measures in determining a company’s credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective. Our current credit ratings are listed in the following table:

Credit Ratings	S&P	Moody’s
Issuer Credit Rating	BBB	Baa1
Commercial Paper	A-2	P-2
First Mortgage Bonds	(a)	A2

(a)    Not rated by S&P.

The disclosure of these credit ratings is not a recommendation to buy, sell or hold our securities. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.

Common Stock Dividends. ALLETE is committed to providing a competitive dividend to its shareholders while at the same time funding its growth. ALLETE’s long-term objective is to maintain a dividend payout ratio similar to our peers and provide for future dividend increases. Our targeted payout range is between 60 percent and 70 percent. In 2021, we paid out 78 percent (74 percent in 2020; 65 percent in 2019) of our per share earnings in dividends. On February 3, 2022, our Board of Directors declared a dividend of $0.65 per share, which is payable on March 1, 2022, to shareholders of record at the close of business on February 15, 2022.

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Capital Requirements

ALLETE’s projected capital expenditures for the years 2022 through 2026 are presented in the following table. Actual capital expenditures may vary from the projections due to changes in forecasted plant maintenance, regulatory decisions or approvals, future environmental requirements, base load growth, capital market conditions or executions of new business strategies. Projected capital expenditures exclude amounts for projects that will be sold to third parties upon completion.

Capital Expenditures		2022	2023	2024	2025	2026	Total
Millions
Regulated Operations		$125	$260	$370	$365	$415	$1,535
ALLETE Clean Energy (a)		10	5	5	5	5	30
Corporate and Other
	South Shore Energy (b)	20	60	45	5	—	130
	Other	55	20	10	10	10	105
Total Capital Expenditures		$210	$345	$430	$385	$430	$1,800

(a)Capital expenditures in 2022 do not include costs related to ALLETE Clean Energy’s projects to repower and sell the 100 MW Northern Wind project or to develop and sell the 92 MW Red Barn project as these projects will be sold upon completion. (See Outlook – ALLETE Clean Energy.)

(b)Our portion of estimated capital expenditures for construction of NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy.

We are well positioned to meet our financing needs due to adequate operating cash flows, available additional working capital and access to capital markets. We will finance capital expenditures from a combination of internally generated funds, debt and equity issuance proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Capital Structure.)

Environmental and Other Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation. (See Note 8. Commitments, Guarantees and Contingencies.)

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Market Risk

Securities Investments.

Available-for-Sale Securities. As of December 31, 2021, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.

INTEREST RATE RISK

We are exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. The following table presents the long-term debt obligations and the corresponding weighted average interest rate as of December 31, 2021:

	Expected Maturity Date
Interest Rate Sensitive Financial Instruments	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value
Long-Term Debt
Fixed Rate – Millions	$89.8	$89.7	$74.4	$213.9	$77.2	$1,143.9	$1,688.9	$1,895.1
Average Interest Rate – %	3.7	5.8	3.9	3.4	3.3	4.1	4.0
Variable Rate – Millions	$124.7	—	—	$172.8	—	—	$297.5	$297.5
Average Interest Rate – %	1.0	—	—	2.8	—	—	2.0

Interest rates on variable rate long-term debt are reset on a periodic basis reflecting prevailing market conditions. Based on the variable rate debt outstanding as of December 31, 2021, an increase of 100 basis points in interest rates would impact the amount of pre-tax interest expense by $3.0 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of December 31, 2021.

COMMODITY PRICE RISK

Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota, and power and natural gas purchased for resale in our regulated service territory in Wisconsin. Minnesota Power’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates or distribution of savings in fuel costs to ratepayers. SWL&P’s exposure to price risk for natural gas is significantly mitigated by the current ratemaking process and regulatory framework, which allows the commodity cost to be passed through to customers. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of power and coal and related transportation costs (Minnesota Power) and natural gas (SWL&P).

POWER MARKETING

Minnesota Power’s power marketing activities consist of: (1) purchasing energy in the wholesale market to serve its regulated service territory when energy requirements exceed generation output; and (2) selling excess available energy and purchased power. From time to time, Minnesota Power may have excess energy that is temporarily not required by retail and municipal customers in our regulated service territory. Minnesota Power actively sells any excess energy to the wholesale market to optimize the value of its generating facilities.

We are exposed to credit risk primarily through our power marketing activities. We use credit policies to manage credit risk, which includes utilizing an established credit approval process and monitoring counterparty limits.

Recently Adopted Accounting Pronouncements.

New accounting pronouncements are discussed in Note 1. Operations and Significant Accounting Policies.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk for information related to quantitative and qualitative disclosure about market risk.

Item 8. Financial Statements and Supplementary Data

See our Consolidated Financial Statements as of December 31, 2021 and 2020, and for the years ended December 31, 2021, 2020 and 2019, and supplementary data, which are indexed in Item 15(a).

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2021, evaluations were performed, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, on the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control – Integrated Framework (framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Controls

There has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

Not applicable.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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Part III

Item 10. Directors, Executive Officers and Corporate Governance

Unless otherwise stated, the information required by this Item is incorporated by reference herein from our Proxy Statement for the 2022 Annual Meeting of Shareholders (2022 Proxy Statement) under the following headings:

•Directors. The information regarding directors will be included in the “Election of Directors” section;

•Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Corporate Governance” section and the “Audit Committee Report” section;

•Audit Committee Members. The identity of the Audit Committee members will be included in the “Corporate Governance” section and the “Audit Committee Report” section;

•Executive Officers. The information regarding executive officers is included in Part I of this Form 10-K; and

•Section 16(a) Delinquency. If applicable, information regarding Section 16(a) delinquencies will be included in a “Delinquent Section 16(a) Reports” section.

Our 2022 Proxy Statement will be filed with the SEC within 120 days after the end of our 2021 fiscal year.

Code of Ethics. We have adopted a written Code of Ethics that applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. A copy of our Code of Ethics is available on our website at www.allete.com and print copies are available without charge upon request to ALLETE, Inc., Attention: Secretary, 30 West Superior St., Duluth, Minnesota 55802. Any amendment to the Code of Ethics or any waiver of the Code of Ethics will be disclosed on our website at www.allete.com promptly following the date of such amendment or waiver.

Corporate Governance. The following documents are available on our website at www.allete.com and print copies are available upon request:

•Corporate Governance Guidelines;

•Audit Committee Charter;

•Executive Compensation Committee Charter; and

•Corporate Governance and Nominating Committee Charter.

Any amendment to these documents will be disclosed on our website at www.allete.com promptly following the date of such amendment.

Item 11. Executive Compensation

The information required by this Item is incorporated by reference herein from the “Compensation Discussion and Analysis,” the “Compensation of Executive Officers,” the “Compensation Committee Report” and the “Director Compensation” sections in our 2022 Proxy Statement.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item is incorporated by reference herein from the “Ownership of ALLETE Common Stock – Securities Owned by Certain Beneficial Owners” and the “Ownership of ALLETE Common Stock – Securities Owned by Directors and Management” sections in our 2022 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth the shares of ALLETE common stock available for issuance under the Company's equity compensation plans as of December 31, 2021:

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (c)
Equity Compensation Plans Approved by Security Holders	127,075	—	772,469
Equity Compensation Plans Not Approved by Security Holders	—	—	—
Total	127,075	—	772,469

(a)    Includes the following as of December 31, 2021: (i) 52,337 securities representing the target number of performance share awards (including accrued dividends) granted under the executive long-term incentive compensation plan that were unvested; and (ii) 74,738 director deferred stock units (including accrued dividends) under the non-employee director compensation deferral plan. With respect to unvested performance share awards, the actual number of shares to be issued will vary from 0 percent to 200 percent of the target level depending upon the achievement of total shareholder return objectives established for such awards. For additional information about the performance shares, including payout calculations, see our 2022 Proxy Statement.

(b)    Earned performance share awards are paid in shares of ALLETE common stock on a one-for-one basis. Accordingly, these awards do not have a weighted-average exercise price.

(c)    Excludes the number of securities shown in the first column as to be issued upon exercise of outstanding options, warrants, and rights. The amount shown is comprised of: (i) 686,026 shares available for issuance under the executive long-term incentive compensation plan in the form of options, rights, restricted stock units, performance share awards, and other grants as approved by the Executive Compensation Committee of the Company’s Board of Directors; (ii) 11,442 shares available for issuance under the Non-Employee Director Stock Plan as payment for a portion of the annual retainer payable to non-employee Directors; and (iii) 75,001 shares available for issuance under the ALLETE and Affiliated Companies Employee Stock Purchase Plan.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this Item is incorporated by reference herein from the “Corporate Governance” section in our 2022 Proxy Statement.

We have adopted a Related Person Transaction Policy which is available on our website at www.allete.com. Print copies are available without charge, upon request. Any amendment to this policy will be disclosed on our website at www.allete.com promptly following the date of such amendment.

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Item 14. Principal Accountant Fees and Services

Our independent registered public accounting firm is PricewaterhouseCoopers LLP, Minneapolis, MN, PCAOB ID: 238.

The information required by this Item is incorporated by reference herein from the “Audit Committee Report” section in our 2022 Proxy Statement.

Part IV

Item 15.     Exhibits and Financial Statement Schedules

(a)	Certain Documents Filed as Part of this Form 10-K.
(1)	Financial Statements	Page
	ALLETE
	Report of Independent Registered Public Accounting Firm	66
	Consolidated Balance Sheet as of December 31, 2021 and 2020	68
	For the Years Ended December 31, 2021, 2020 and 2019
	Consolidated Statement of Income	69
	Consolidated Statement of Comprehensive Income	70
	Consolidated Statement of Cash Flows	71
	Consolidated Statement of Equity	72
	Notes to Consolidated Financial Statements	73
(2)	Financial Statement Schedules
	Schedule II – ALLETE Valuation and Qualifying Accounts and Reserves	122
	All other schedules have been omitted either because the information is not required to be reported by ALLETE or because the information is included in the Consolidated Financial Statements or the notes.
(3)	Exhibits including those incorporated by reference.

Exhibit Number
*2	—	Stock Purchase Agreement by and among Global Water Services Holding Company, Inc., ALLETE Enterprises, Inc., and Kurita American Holdings Inc., dated February 8, 2019 (filed as Exhibit 2 to the March 31, 2019, Form 10-Q, File No. 1-3548).
*3(a)1	—	Articles of Incorporation, amended and restated as of May 8, 2001 (filed as Exhibit 3(b) to the March 31, 2001, Form 10‑Q, File No. 1-3548).
*3(a)2	—	Amendment to Articles of Incorporation, dated as of September 20, 2004 (filed as Exhibit 3 to the September 21, 2004, Form 8-K, File No. 1-3548).
*3(a)3	—	Amendment to Articles of Incorporation, dated as of May 12, 2009 (filed as Exhibit 3 to the June 30, 2009, Form 10-Q, File No. 1-3548).
*3(a)4	—	Amendment to Articles of Incorporation, dated as of May 11, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548).
*3(a)5	—	Amendment to Certificate of Assumed Name, filed with the Minnesota Secretary of State on May 8, 2001 (filed as Exhibit 3(a) to the March 31, 2001, Form 10-Q, File No. 1-3548).
*3(b)		Bylaws, as amended effective April 13, 2020 (filed as Exhibit 3 to the April 14, 2020, Form 8-K, File No. 1-3548).
*4(a)1	—	Mortgage and Deed of Trust, dated as of September 1, 1945, between Minnesota Power & Light Company (now ALLETE) and The Bank of New York Mellon (formerly Irving Trust Company) and Eva Waite (successor to Richard H. West), Trustees (filed as Exhibit 7(c), File No. 2-5865).
*4(a)2	—	Supplemental Indentures to ALLETE’s Mortgage and Deed of Trust:
		Number	Dated as of	Reference File	Exhibit
		First	March 1, 1949	2-7826	7(b)
		Second	July 1, 1951	2-9036	7(c)
		Third	March 1, 1957	2-13075	2(c)
		Fourth	January 1, 1968	2-27794	2(c)
		Fifth	April 1, 1971	2-39537	2(c)
		Sixth	August 1, 1975	2-54116	2(c)

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Exhibit Number
		Seventh	September 1, 1976	2-57014	2(c)
		Eighth	September 1, 1977	2-59690	2(c)
		Ninth	April 1, 1978	2-60866	2(c)
		Tenth	August 1, 1978	2-62852	2(d)2
		Eleventh	December 1, 1982	2-56649	4(a)3
		Twelfth	April 1, 1987	33-30224	4(a)3
		Thirteenth	March 1, 1992	33-47438	4(b)
		Fourteenth	June 1, 1992	33-55240	4(b)
		Fifteenth	July 1, 1992	33-55240	4(c)
		Sixteenth	July 1, 1992	33-55240	4(d)
		Seventeenth	February 1, 1993	33-50143	4(b)
		Eighteenth	July 1, 1993	33-50143	4(c)
		Nineteenth	February 1, 1997	1-3548 (1996 Form 10-K)	4(a)3
		Twentieth	November 1, 1997	1-3548 (1997 Form 10-K)	4(a)3
		Twenty-first	October 1, 2000	333-54330	4(c)3
		Twenty-second	July 1, 2003	1-3548 (June 30, 2003, Form 10-Q)	4
		Twenty-third	August 1, 2004	1-3548 (Sept. 30, 2004, Form 10-Q)	4(a)
		Twenty-fourth	March 1, 2005	1-3548 (March 31, 2005, Form 10-Q)	4
		Twenty-fifth	December 1, 2005	1-3548 (March 31, 2006, Form 10-Q)	4
		Twenty-sixth	October 1, 2006	1-3548 (2006 Form 10-K)	4(a)3
		Twenty-seventh	February 1, 2008	1-3548 (2007 Form 10-K)	4(a)3
		Twenty-eighth	May 1, 2008	1-3548 (June 30, 2008, Form 10-Q)	4
		Twenty-ninth	November 1, 2008	1-3548 (2008 Form 10-K)	4(a)3
		Thirtieth	January 1, 2009	1-3548 (2008 Form 10-K)	4(a)4
		Thirty-first	February 1, 2010	1-3548 (March 31, 2010, Form 10-Q)	4
		Thirty-second	August 1, 2010	1-3548 (Sept. 30, 2010, Form 10-Q)	4
		Thirty-third	July 1, 2012	1-3548 (July 2, 2012, Form 8-K)	4
		Thirty-fourth	April 1, 2013	1-3548 (April 2, 2013, Form 8-K)	4
		Thirty-fifth	March 1, 2014	1-3548 (March 31, 2014, Form 10-Q)	4
		Thirty-sixth	June 1, 2014	1-3548 (June 30, 2014, Form 10-Q)	4
		Thirty-seventh	September 1, 2014	1-3548 (Sept. 30, 2014, Form 10-Q)	4
		Thirty-eighth	September 1, 2015	1-3548 (Sept. 30, 2015, Form 10-Q)	4(a)
		Thirty-ninth	April 1, 2018	1-3548 (March 31, 2018, Form 10-Q)	4
		Fortieth	March 1, 2019	1-3548 (March 31, 2019, Form 10-Q)	4(a)
		Forty-first	August 1, 2020	1-3548 (Sept. 30, 2020, Form 10-Q)	4(a)
		Forty-second	September 1, 2021	1-3548 (Sept. 30, 2021, Form 10-Q)	4
*4(b)1	—	Mortgage and Deed of Trust, dated as of March 1, 1943, between Superior Water, Light and Power Company and Chemical Bank & Trust Company and Howard B. Smith, as Trustees, both succeeded by U.S. Bank National Association, as Trustee (filed as Exhibit 7(c), File No. 2-8668).
*4(b)2	—	Supplemental Indentures to Superior Water, Light and Power Company’s Mortgage and Deed of Trust:
		Number	Dated as of	Reference File	Exhibit
		First	March 1, 1951	2-59690	2(d)(1)
		Second	March 1, 1962	2-27794	2(d)1
		Third	July 1, 1976	2-57478	2(e)1
		Fourth	March 1, 1985	2-78641	4(b)
		Fifth	December 1, 1992	1-3548 (1992 Form 10-K)	4(b)1
		Sixth	March 24, 1994	1-3548 (1996 Form 10-K)	4(b)1
		Seventh	November 1, 1994	1-3548 (1996 Form 10-K)	4(b)2
		Eighth	January 1, 1997	1-3548 (1996 Form 10-K)	4(b)3
		Ninth	October 1, 2007	1-3548 (2007 Form 10-K)	4(c)3
		Tenth	October 1, 2007	1-3548 (2007 Form 10-K)	4(c)4
		Eleventh	December 1, 2008	1-3548 (2008 Form 10-K)	4(c)3

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60

Exhibit Number
		Twelfth	December 2, 2013	1-3548 (2013 Form 10-K)	4(c)3
		Thirteenth	May 29, 2018	1-3548 (June 30, 2018, Form 10-Q)	4
		Fourteenth	June 14, 2021	1-3548 (June 30, 2021, Form 10-Q)	4(a)
		Fifteenth	June 14, 2021	1-3548 (June 30, 2021, Form 10-Q)	4(b)
*4(c)	—	Note Purchase and Guarantee Agreement dated as of November 5, 2015, among Armenia Mountain Wind LLC, AMW I Holding, LLC and the purchasers named therein (filed as Exhibit 4 to the November 12, 2015, Form 8-K, File No. 1-3548).
*4(d)	—	Note Purchase Agreement, dated December 8, 2016, between ALLETE and Hartford Investment Management Company, Northwestern Mutual Investment Management Company, The Northwestern Mutual Life Insurance Company and Nationwide Life insurance Company (filed as Exhibit 4 to the December 12, 2016, Form 8-K, File No. 1-3548).
*4(f)	—	Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (filed as Exhibit 4(h) to the 2019 Form 10-K, File No. 1-3548).
*4(h)	—	Note Purchase Agreement, dated September 10, 2020, between ALLETE and the purchasers named therein (filed as Exhibit 4 to the September 30, 2020, Form 10-Q, File No. 1-3548).
*10(a)	—	Power Purchase and Sale Agreement, dated as of May 29, 1998, between Minnesota Power, Inc. (now ALLETE) and Square Butte Electric Cooperative (filed as Exhibit 10 to the June 30, 1998, Form 10-Q, File No. 1-3548).
*10(b)1	—	Amended and Restated Credit Agreement dated as of January 10, 2019 among ALLETE, as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Chase Bank, N.A., as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 10(b)2 to the 2018 Form 10-K, File No. 1-3548).
*10(b)2	—	First Amendment to Credit Agreement dated May 15, 2019, among ALLETE, as Borrower, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the June 30, 2019, Form 10-Q, File No. 1-3548).
10(b)3	—	Second Amendment to Credit Agreement dated November 23, 2021, among ALLETE, as Borrower, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
*10(c)1	—	Financing Agreement between Collier County Industrial Development Authority and ALLETE dated as of July 1, 2006 (filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File No. 1-3548).
*10(c)2	—	Amended and Restated Letter of Credit Agreement, dated as of June 3, 2011, among ALLETE, the participating banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (filed as Exhibit 10(b) to the June 30, 2011, Form 10-Q, File No. 1-3548).
*10(c)3	—	First Amendment to Amended and Restated Letter of Credit Agreement, dated as of June 1, 2013, between ALLETE and Wells Fargo Bank, National Association, as Issuing Bank, Administrative Agent and Sole Participating Bank (filed as Exhibit 10(b) to the June 30, 2013, Form 10-Q, File No. 1-3548).
*10(d)	—	Agreement dated December 16, 2005, among ALLETE, Wisconsin Public Service Corporation and WPS Investments, LLC (filed as Exhibit 10(g) to the 2009 Form 10-K, File No. 1-3548).
*+10(e)1	—	ALLETE Executive Annual Incentive Plan, as amended and restated, effective January 1, 2011 (filed as Exhibit 10(h)1 to the 2010 Form 10-K, File No. 1-3548).
*+10(e)2	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2017 (filed as Exhibit 10(e)6 to the 2016 Form 10-K, File No. 1-3548).
*+10(e)3	—	ALLETE Executive Annual Incentive Plan Form of Award Superior Water, Light and Power Effective 2017 (filed as Exhibit 10(e)7 to the 2016 Form 10-K, File No. 1-3548).
*+10(e)4	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2018 (filed as Exhibit 10(a)1 to the March 31, 2018, Form 10-Q, File No. 1-3548).
*+10(e)5	—	ALLETE Executive Annual Incentive Plan Form of Award Superior Water, Light and Power Effective 2018 (filed as Exhibit 10(a)2 to the March 31, 2018, Form 10-Q, File No. 1-3548).
*+10(e)6	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2019 (filed as Exhibit 10(e)7 to the 2018 Form 10-K, File No. 1-3548).
*+10(e)7	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2020 (filed as Exhibit 10(e)8 to the 2019 Form 10-K, File No. 1-3548).
*+10(e)8	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2021 (filed as Exhibit 10(e)8 to the 2020 Form 10-K, File No. 1-3548).
+10(e)9	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2022.
*+10(f)1	—	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), as amended and restated, effective January 1, 2009 (filed as Exhibit 10(i)4 to the 2008 Form 10-K, File No. 1-3548).
*+10(f)2	—	Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), effective January 1, 2011 (filed as Exhibit 10(i)2 to the 2010 Form 10-K, File No. 1-3548).
*+10(f)4	—	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2019 (filed as Exhibit 10(f)4 to the 2018 Form 10-K, File No. 1-3548).
+10(f)5		ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2021.

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61

Exhibit Number
*+10(g)	—	ALLETE Deferred Compensation Trust Agreement, as amended and restated, effective December 15, 2012 (filed as Exhibit 10(j) to the 2012 Form 10-K, File No. 1-3548).
*+10(i)1	—	ALLETE Executive Long-Term Incentive Compensation Plan effective January 1, 2016 (filed November 6, 2015, as Exhibit 99 to Form S-8, File No. 333-207846).
*+10(i)2	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2016 (filed as Exhibit 10(k)3 to the 2015 Form 10-K, File No. 1-3548).
*+10(i)3	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2016 (filed as Exhibit 10(k)2 to the 2015 Form 10-K, File No. 1-3548).
*+10(i)5	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2017 (filed as Exhibit 10(i)5 to the 2016 Form 10-K, File No. 1-3548).
*+10(i)6	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2017 (filed as Exhibit 10(i)6 to the 2016 Form 10-K, File No. 1-3548).
*+10(i)7	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Cash Award Effective 2018 (filed as Exhibit 10(b) to the March 31, 2018, Form 10-Q, File No. 1-3548).
*+10(i)8	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2018 (filed as Exhibit 10(i)7 to the 2017 Form 10-K, File No. 1-3548).
*+10(i)9	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2018 (filed as Exhibit 10(i)8 to the 2017 Form 10-K, File No. 1-3548).
*+10(i)10	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2019 (filed as Exhibit 10(i)10 to the 2018 Form 10-K, File No. 1-3548).
*+10(i)11	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2019 (filed as Exhibit 10(i)11 to the 2018 Form 10-K, File No. 1-3548).
*+10(i)12	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2020 (filed as Exhibit 10(i)12 to the 2019 Form 10-K, File No. 1-3548).
*+10(i)13	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2020 (filed as Exhibit 10(i)13 to the 2019 Form 10-K, File No. 1-3548).
*+10(i)14	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2021 (filed as Exhibit 10(i)14 to the 2020 Form 10-K, File No. 1-3548).
*+10(i)15	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2021 (filed as Exhibit 10(i)15 to the 2020 Form 10-K, File No. 1-3548).
*+10(i)16	—	Description of Compensation Arrangement 2021 with respect to Alan R. Hodnik (incorporated by reference from the Form 8-K, dated January 30, 2020, File No. 1-3548).
+10(i)17	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2022.
+10(i)18	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2022.
*+10(j)1	—	Amended and Restated ALLETE Non-Employee Director Stock Plan, effective May 15, 2013 (filed as Exhibit 10(a) to the June 30, 2013, Form 10-Q, File No. 1-3548).
*+10(k)2	—	ALLETE Non-Employee Director Compensation Summary effective January 1, 2019 (filed as Exhibit 10(k)3 to the 2018 Form 10-K, File No. 1-3548).
*+10(k)3	—	ALLETE Non-Employee Director Compensation Summary effective January 1, 2020 (filed as Exhibit 10(k)3 to the 2020 Form 10-K, File No. 1-3548).
+10(k)4		ALLETE Non-Employee Director Compensation Summary effective January 1, 2022
*+10(l)1	—	Minnesota Power (now ALLETE) Non-Employee Director Compensation Deferral Plan Amended and Restated, effective January 1, 1990 (filed as Exhibit 10(ac) to the 2002 Form 10-K, File No. 1-3548).
*+10(l)2	—	October 2003 Amendment to the Minnesota Power (now ALLETE) Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548).
*+10(l)3	—	January 2005 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(c) to the March 31, 2005, Form 10-Q, File No. 1-3548).
*+10(l)4	—	October 2006 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548).
*+10(l)5	—	July 2012 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(n)5 to the 2012 Form 10-K, File No. 1-3548).
*+10(m)1	—	ALLETE Non-Employee Director Compensation Deferral Plan II, effective May 1, 2009 (filed as Exhibit 10(a) to the June 30, 2009, Form 10-Q, File No. 1-3548).
*+10(m)2	—	ALLETE Non-Employee Director Compensation Deferral Plan II, as amended and restated, effective July 24, 2012 (filed as Exhibit 10(o)2 to the 2012 Form 10-K, File No. 1-3548).
*+10(n)	—	ALLETE Non-Employee Director Compensation Trust Agreement, as amended and restated, effective December 15, 2012 (filed as Exhibit 10(p)2 to the 2012 Form 10-K, File No. 1-3548).

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Exhibit Number
*+10(o)1	—	ALLETE and Affiliated Companies Change in Control Severance Plan, as amended and restated, effective January 19, 2011 (filed as Exhibit 10(q) to the 2010 Form 10-K, File No. 1-3548).
*+10(o)2	—	ALLETE and Affiliated Companies Change in Control Severance Plan, as amended and restated, effective April 23, 2018 (filed as Exhibit 10(c) to the March 31, 2018, Form 10-Q, File No. 1-3548).
21	—	Subsidiaries of the Registrant.
23	—	Consent of Independent Registered Public Accounting Firm.
31(a)	—	Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)	—	Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	—	Section 1350 Certification of Annual Report by the Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95	—	Mine Safety.
99	—	ALLETE News Release dated February 16, 2022, announcing earnings for the year ended December 31, 2021. (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)
101.INS	—	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	—	XBRL Schema
101.CAL	—	XBRL Calculation
101.DEF	—	XBRL Definition
101.LAB	—	XBRL Label
101.PRE	—	XBRL Presentation
104	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, other long-term debt instruments are not filed as exhibits because the total amount of debt authorized under each omitted instrument does not exceed 10 percent of our total consolidated assets. We will furnish copies of these instruments to the SEC upon its request.

*	Incorporated herein by reference as indicated.
+	Management contract or compensatory plan or arrangement pursuant to Item 15(b).

Item 16. Form 10-K Summary

None.

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63

Signatures

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

			ALLETE, Inc.
Dated:	February 16, 2022	By	/s/ Bethany M. Owen
			Bethany M. Owen
			Chair, President and Chief Executive Officer

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 and on the dates indicated.

Signature	Title	Date
/s/ Bethany M. Owen	Chair, President and Chief Executive Officer	February 16, 2022
Bethany M. Owen	(Principal Executive Officer) and Director
/s/ Steven W. Morris	Senior Vice President and Chief Financial Officer	February 16, 2022
Steven W. Morris	(Principal Financial Officer and Principal Accounting Officer)

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Signatures (Continued)

Signature	Title	Date
/s/ Kathryn W. Dindo	Director	February 16, 2022
Kathryn W. Dindo
/s/ George G. Goldfarb	Director	February 16, 2022
George G. Goldfarb
/s/ James J. Hoolihan	Director	February 16, 2022
James J. Hoolihan
/s/ Heidi E. Jimmerson	Director	February 16, 2022
Heidi E. Jimmerson
/s/ Madeleine W. Ludlow	Director	February 16, 2022
Madeleine W. Ludlow
/s/ Susan K. Nestegard	Director	February 16, 2022
Susan K. Nestegard
/s/ Douglas C. Neve	Director	February 16, 2022
Douglas C. Neve
/s/ Barbara A. Nick	Director	February 16, 2022
Barbara A. Nick
/s/ Robert P. Powers	Director	February 16, 2022
Robert P. Powers
/s/ Charlene A. Thomas	Director	February 16, 2022
Charlene A. Thomas

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65

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of ALLETE, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of ALLETE, Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and December 31, 2020, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and December 31, 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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66

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated 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.

Accounting for the Effects of Regulatory Matters

As described in Note 4 to the consolidated financial statements, the Company’s regulated utility operations are subject to accounting standards for the effects of certain types of regulation. As of December 31, 2021, there was $512 million of regulatory assets and $545 million of regulatory liabilities recorded. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. Management assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. As disclosed by management, these standards require the Company to reflect the effect of regulatory decisions in its financial statements. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income.

The principal consideration for our determination that performing procedures relating to the Company’s accounting for the effects of regulatory matters is a critical audit matter is the significant judgment by management in determining the recoverability of costs; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence obtained related to the recoverability of costs.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation of new regulatory orders, changes to existing regulatory orders, and assessing the recoverability of costs. These procedures also included, among others, evaluating (i) the reasonableness of management’s assessment of impacts arising from correspondence with regulators and changes in laws and regulations, (ii) management’s judgments related to the recoverability of regulatory assets and the establishment of regulatory liabilities, and (iii) the sufficiency of the disclosures in the consolidated financial statements. Testing the regulatory assets and liabilities involved considering the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of relevant regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Minneapolis, Minnesota

February 16, 2022

We have served as the Company’s auditor since 1963.

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67

CONSOLIDATED FINANCIAL STATEMENTS

ALLETE Consolidated Balance Sheet

As of December 31	2021	2020
Millions
Assets
Current Assets
Cash and Cash Equivalents	$45.1	$44.3
Accounts Receivable (Less Allowance of $1.8 and $2.5)	123.7	111.9
Inventories – Net	97.7	74.2
Prepayments and Other	24.8	24.5
Total Current Assets	291.3	254.9
Property, Plant and Equipment – Net	5,100.2	4,840.8
Regulatory Assets	511.8	480.9
Equity Investments	318.0	301.2
Other Non-Current Assets	213.7	206.8
Total Assets	$6,435.0	$6,084.6
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable	$111.0	$110.0
Accrued Taxes	65.1	59.4
Accrued Interest	20.1	19.8
Long-Term Debt Due Within One Year	214.2	203.7
Other	133.0	66.7
Total Current Liabilities	543.4	459.6
Long-Term Debt	1,763.2	1,593.2
Deferred Income Taxes	185.7	195.7
Regulatory Liabilities	536.1	524.8
Defined Benefit Pension and Other Postretirement Benefit Plans	179.5	225.8
Other Non-Current Liabilities	280.8	285.3
Total Liabilities	3,488.7	3,284.4
Commitments, Guarantees and Contingencies (Note 8)
Equity
ALLETE Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 53.2 and 52.1 Shares Issued and Outstanding	1,536.7	1,460.9
Accumulated Other Comprehensive Loss	(23.8)	(31.1)
Retained Earnings	900.2	864.8
Total ALLETE Equity	2,413.1	2,294.6
Non-Controlling Interest in Subsidiaries	533.2	505.6
Total Equity	2,946.3	2,800.2
Total Liabilities and Equity	$6,435.0	$6,084.6

The accompanying notes are an integral part of these statements.

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68

ALLETE Consolidated Statement of Income

Year Ended December 31	2021	2020	2019
Millions Except Per Share Amounts
Operating Revenue
Contracts with Customers – Utility	$1,227.9	$987.3	$1,042.4
Contracts with Customers – Non-utility	179.9	170.5	186.5
Other – Non-utility	11.4	11.3	11.6
Total Operating Revenue	1,419.2	1,169.1	1,240.5
Operating Expenses
Fuel, Purchased Power and Gas – Utility	562.4	358.6	390.7
Transmission Services – Utility	75.3	67.0	69.8
Cost of Sales – Non-utility	68.8	66.7	80.6
Operating and Maintenance	259.2	252.0	264.3
Depreciation and Amortization	231.7	217.8	202.0
Taxes Other than Income Taxes	70.5	56.1	53.3
Total Operating Expenses	1,267.9	1,018.2	1,060.7
Operating Income	151.3	150.9	179.8
Other Income (Expense)
Interest Expense	(69.1)	(65.6)	(64.9)
Equity Earnings	20.0	22.1	21.7
Gain on Sale of U.S. Water Services	—	—	23.6
Other	8.7	14.7	18.7
Total Other Expense	(40.4)	(28.8)	(0.9)
Income Before Non-Controlling Interest and Income Taxes	110.9	122.1	178.9
Income Tax Benefit	(26.9)	(39.5)	(6.6)
Net Income	137.8	161.6	185.5
Net Loss Attributable to Non-Controlling Interest	(31.4)	(12.6)	(0.1)
Net Income Attributable to ALLETE	$169.2	$174.2	$185.6
Average Shares of Common Stock
Basic	52.4	51.9	51.6
Diluted	52.5	51.9	51.7
Basic Earnings Per Share of Common Stock	$3.23	$3.36	$3.59
Diluted Earnings Per Share of Common Stock	$3.23	$3.35	$3.59

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Comprehensive Income

Year Ended December 31	2021	2020	2019
Millions
Net Income	$137.8	$161.6	$185.5
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Securities
Net of Income Tax (Benefit) Expense of $(0.1), $0.1 and $0.1	(0.1)	0.1	0.2
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Tax (Benefit) Expense of $3.0, $(3.1) and $1.4	7.4	(7.6)	3.5
Total Other Comprehensive Income (Loss)	7.3	(7.5)	3.7
Total Comprehensive Income	145.1	154.1	189.2
Net Loss Attributable to Non-Controlling Interest	(31.4)	(12.6)	(0.1)
Total Comprehensive Income Attributable to ALLETE	$176.5	$166.7	$189.3

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Cash Flows

Year Ended December 31	2021	2020	2019
Millions
Operating Activities
Net Income	$137.8	$161.6	$185.5
AFUDC – Equity	(2.6)	(1.9)	(2.3)
Income from Equity Investments – Net of Dividends	2.2	(3.2)	(5.6)
Gain on Investments and Property, Plant and Equipment	(0.8)	(1.3)	(1.6)
Depreciation Expense	231.6	217.7	200.6
Amortization of PSAs	(11.4)	(11.3)	(11.6)
Amortization of Other Intangible Assets and Other Assets	9.9	10.4	11.7
Deferred Income Tax Benefit	(26.9)	(39.5)	(6.7)
Share-Based and ESOP Compensation Expense	5.9	6.1	6.3
Defined Benefit Pension and Other Postretirement Benefit Expense	4.3	0.1	1.2
Bad Debt Expense	1.2	2.7	(0.1)
Payments for Interim Rate Refund	—	—	(40.0)
Payments for Tax Reform Refund	—	(0.2)	(10.4)
Gain on Sale of U.S. Water Services	—	—	(23.6)
Changes in Operating Assets and Liabilities
Accounts Receivable	(13.0)	(18.2)	22.6
Inventories	(23.5)	(1.4)	(4.1)
Prepayments and Other	(0.5)	0.9	0.3
Accounts Payable	15.0	11.8	(8.8)
Other Current Liabilities	28.0	11.7	(13.7)
Cash Contributions to Defined Benefit Pension Plans	(10.3)	(10.7)	(10.4)
Changes in Fuel Adjustment Clause Regulatory Asset and Liability	(56.4)	5.0	—
Changes in Regulatory and Other Non-Current Assets	(12.0)	(31.0)	(25.2)
Changes in Regulatory and Other Non-Current Liabilities	(15.0)	(9.5)	(17.2)
Cash from Operating Activities	263.5	299.8	246.9
Investing Activities
Proceeds from Sale of Available-for-sale Securities	6.4	12.8	12.1
Payments for Purchase of Available-for-sale Securities	(3.6)	(8.7)	(12.2)
Payments for Equity Investments	(17.6)	(99.1)	(37.9)
Return of Capital from Equity Investments	—	—	8.3
Additions to Property, Plant and Equipment	(473.3)	(717.8)	(597.1)
Proceeds from Sale of U.S. Water Services – Net of Transaction Costs and Cash Retained	—	—	268.6
Other Investing Activities	2.9	—	15.5
Cash for Investing Activities	(485.2)	(812.8)	(342.7)
Financing Activities
Proceeds from Issuance of Common Stock	69.9	18.1	1.9
Proceeds from Issuance of Short-Term and Long-Term Debt	733.0	672.4	201.9
Repayments of Short-Term and Long-Term Debt	(552.9)	(488.6)	(72.2)
Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs	90.9	414.5	103.8
Acquisition-Related Contingent Consideration Payments	—	—	(3.8)
Dividends on Common Stock	(131.9)	(128.2)	(121.4)
Other Financing Activities	(4.8)	(2.5)	(0.9)
Cash from Financing Activities	204.2	485.7	109.3
Change in Cash, Cash Equivalents and Restricted Cash	(17.5)	(27.3)	13.5
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	65.2	92.5	79.0
Cash, Cash Equivalents and Restricted Cash at End of Period	$47.7	$65.2	$92.5

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Equity

	2021	2020	2019
Millions Except Per Share Amounts
Common Stock
Balance, Beginning of Period	$1,460.9	$1,436.7	$1,428.5
Common Stock Issued	75.8	24.2	8.2
Balance, End of Period	1,536.7	1,460.9	1,436.7
Accumulated Other Comprehensive Loss
Balance, Beginning of Period	(31.1)	(23.6)	(27.3)
Other Comprehensive Income – Net of Income Taxes
Unrealized Gain (Loss) on Debt Securities	(0.1)	0.1	0.2
Defined Benefit Pension and Other Postretirement Plans	7.4	(7.6)	3.5
Balance, End of Period	(23.8)	(31.1)	(23.6)
Retained Earnings
Balance, Beginning of Period	864.8	818.8	754.6
Net Income Attributable to ALLETE	169.2	174.2	185.6
Common Stock Dividends	(131.9)	(128.2)	(121.4)
Adjustment of Redeemable Non-Controlling Interest	(1.9)	—	—
Balance, End of Period	900.2	864.8	818.8
Non-Controlling Interest in Subsidiaries
Balance, Beginning of Period	505.6	103.7	—
Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs	90.9	414.5	103.8
Net Loss Attributable to Non-Controlling Interest	(31.4)	(12.6)	(0.1)
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities	(28.8)	—	—
Distributions to Non-Controlling Interest	(3.1)	—	—
Balance, End of Period	533.2	505.6	103.7
Total Equity	$2,946.3	$2,800.2	$2,335.6
Dividends Per Share of Common Stock	$2.52	$2.47	$2.35

The accompanying notes are an integral part of these statements.

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72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with GAAP. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. Actual results could differ from those estimates.

Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.

Principles of Consolidation. Our Consolidated Financial Statements include the accounts of ALLETE, all of our majority‑owned subsidiary companies and variable interest entities of which ALLETE is the primary beneficiary. All material intercompany balances and transactions have been eliminated in consolidation.

Variable Interest Entities. The accounting guidance for “Variable Interest Entities” (VIE) is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether ALLETE is the primary beneficiary of a VIE, management considers whether ALLETE has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. The accounting guidance for VIEs applies to certain ALLETE Clean Energy wind energy facilities and our investment in Nobles 2. (See Tax Equity Financing.)

Business Segments. We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 150,000 retail customers. Minnesota Power also has 15 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in seven states, more than 1,300 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 200 MW of wind energy facilities under contract for sale to others. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

U.S. Water Services provided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. In March 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Corporate and Other is comprised of BNI Energy, our investment in Nobles 2, South Shore Energy, ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 acres of land in Minnesota, and earnings on cash and investments.

BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2021, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 8. Commitments, Guarantees and Contingencies.)

Our investment in Nobles 2 represents a 49 percent equity interest in Nobles 2, the entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power.

South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary, is developing NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to a capacity dedication agreement. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $700 million, of which South Shore Energy’s portion is expected to be approximately $150 million. South Shore Energy’s portion of NTEC project costs incurred through December 31, 2021, is approximately $5 million.

On October 1, 2021, South Shore Energy sold a portion of its undivided ownership interest in NTEC for approximately $20 million representing reimbursement of current costs plus a fee for prior development costs and risks incurred. Following the transaction, South Shore Energy now owns a 20 percent undivided ownership interest in NTEC, Basin owns a 30 percent undivided ownership interest in NTEC and Dairyland Power Cooperative continues to own a 50 percent undivided ownership interest in NTEC. The closing of the transaction resulted in the recognition of an approximately $8.5 million after-tax gain recorded in Corporate and Other in the fourth quarter of 2021, related to prior development costs and risks incurred.

ALLETE Properties represents our legacy Florida real estate investment. Our strategy incorporates the possibility of a bulk sale of the entire ALLETE Properties portfolio. Proceeds from a bulk sale would be strategically deployed to support growth at our Regulated Operations and ALLETE Clean Energy. ALLETE Properties continues to pursue sales of individual parcels over time and will continue to maintain key entitlements and infrastructure.

Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. As of December 31, 2021, and 2020, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement. The December 31, 2019 amount also includes deposits required under tax equity financing agreements. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs. The December 31, 2020 and 2019 amounts also include deposits required under tax equity financing agreements. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amounts presented in the Consolidated Statement of Cash Flows.

Cash, Cash Equivalents and Restricted Cash
As of December 31	2021	2020	2019
Millions
Cash and Cash Equivalents	$45.1	$44.3	$69.3
Restricted Cash included in Prepayments and Other	0.3	0.8	2.8
Restricted Cash included in Other Non-Current Assets	2.3	20.1	20.4
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows	$47.7	$65.2	$92.5

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flow Information.

Consolidated Statement of Cash Flows
Year Ended December 31	2021	2020	2019
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$66.8	$62.0	$63.5
Recognition of Right-of-use Assets and Lease Liabilities (a)	—	—	28.7
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(14.0)	$(67.0)	$33.9
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities (b)	$30.6	—	—
Capitalized Asset Retirement Costs	$16.9	$4.1	$20.7
AFUDC–Equity	$2.6	$1.9	$2.3

(a)Amount of the right-of-use asset and lease liability recognized with the adoption of an accounting standards update for leases.

(b)Amount reclassified to Current Liabilities resulting from the exercise of an option to buy out a non-controlling interest.

Accounts Receivable. Accounts receivable are reported on the Consolidated Balance Sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific situations and such other factors that, in our judgment, deserve recognition in estimating losses.

Accounts Receivable
As of December 31	2021	2020
Millions
Trade Accounts Receivable
Billed	$100.8	$93.5
Unbilled	24.7	20.9
Less: Allowance for Doubtful Accounts	1.8	2.5
Total Accounts Receivable	$123.7	$111.9

Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $7.8 million as of December 31, 2021 ($10.3 million as of December 31, 2020). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. Minnesota Power’s taconite customers, which are currently owned by two entities at the end of 2021, accounted for approximately 32 percent of Regulated Operations operating revenue and approximately 28 percent of consolidated operating revenue in 2021 (29 percent of Regulated Operations operating revenue and 25 percent of consolidated operating revenue in 2020). In 2019, a single entity accounted for approximately 14 percent of Regulated Operations operating revenue and 12 percent of consolidated operating revenue.

Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals.

Available-for-Sale Securities. Available-for-sale debt and equity securities are recorded at fair value. Unrealized gains and losses on available-for-sale debt securities are included in accumulated other comprehensive income (loss), net of tax. Unrealized gains and losses on available-for-sale equity securities are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold.

Inventories – Net. Inventories are stated at the lower of cost or net realizable value. Inventories in our Regulated Operations segment are carried at an average cost or first-in, first-out basis. Inventories in our ALLETE Clean Energy segment and Corporate and Other businesses are carried at an average cost, first-in, first-out or specific identification basis.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Inventories – Net
As of December 31	2021	2020
Millions
Fuel (a)	$18.7	$23.1
Materials and Supplies	56.1	51.1
Construction of Wind Energy Facilities (b)	22.9	—
Total Inventories – Net	$97.7	$74.2

(a)    Fuel consists primarily of coal inventory at Minnesota Power.

(b) Project costs related to ALLETE Clean Energy’s Northern Wind and Red Barn wind projects which are expected be sold in late 2022 and 2023, respectively. (See Other Current Liabilities.)

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the Consolidated Balance Sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on property, plant and equipment for Corporate and Other operations are recognized when they are retired or otherwise disposed. When property, plant and equipment in our Regulated Operations and ALLETE Clean Energy segments are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for component depreciation except for certain circumstances where the retirement is unforeseen or unexpected. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 2. Property, Plant and Equipment.)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. Minnesota Power’s 2015 IRP contained steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in 2016, and the ceasing of coal-fired operations at Taconite Harbor in 2020. As of December 31, 2021, Taconite Harbor had a net book value of approximately $45 million. The MPUC order for the 2015 IRP also directed Minnesota Power to retire Boswell Units 1 and 2, which occurred in the fourth quarter of 2018. As part of the 2016 general retail rate case, the MPUC allowed recovery of the remaining book value of Boswell Units 1 and 2 through 2022. In its latest IRP filing, Minnesota Power proposed retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Boswell Unit 3 and Unit 4 have a net book value of approximately $245 million and $435 million, respectively, as of December 31, 2021. (See Note 4. Regulatory Matters.) We do not expect to record any impairment charge as a result of these operating changes at Taconite Harbor and Boswell. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives.

Impairment of Long-Lived Assets. We review our long-lived assets for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. This includes our property, plant and equipment (see Property, Plant and Equipment) and land inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value.

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our long‑lived assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future use; sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to maintain the operations.

We continue to monitor changes in the broader energy markets along with wind resource expectations that could indicate impairment at ALLETE Clean Energy wind energy facilities upon contract expirations. A continued decline in energy prices or lower wind resource expectations could result in a future impairment.

In 2021, 2020, and 2019, there were no indicators of impairment for our property, plant, and equipment or land inventory. As a result, no impairment was recorded in 2021, 2020 or 2019.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings and commodity price risk related to sales to retail and municipal customers as well as other power suppliers. We have determined that either these agreements are not derivatives, or, if they are derivatives, the agreements qualify for the normal purchases and normal sales exception to derivative accounting guidance; therefore, derivative accounting is not required.

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 12. Employee Stock and Incentive Plans.)

Other Non-Current Assets
As of December 31	2021	2020
Millions
Contract Assets (a)	$23.3	$25.5
Operating Lease Right-of-use Assets	16.4	22.4
ALLETE Properties	19.4	18.2
Restricted Cash	2.3	20.1
Other Postretirement Benefit Plans	64.8	34.2
Other	87.5	86.4
Total Other Non-Current Assets	$213.7	$206.8

(a)    Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue.

Other Current Liabilities
As of December 31	2021	2020
Millions
Customer Deposits (a)	$27.2	$7.4
PSAs	12.6	12.5
Manufactured Gas Plant (b)	12.8	—
Fuel Adjustment Clause	5.0	3.7
Operating Lease Liabilities	4.8	5.9
Redeemable Non-Controlling Interest (c)	30.6	—
Other	40.0	37.2
Total Other Current Liabilities	$133.0	$66.7

(a)    Primarily related to deposits received by ALLETE Clean Energy for the Northern Wind and Red Barn wind projects which are expected be sold in late 2022 and 2023 respectively. (See Inventories – Net.)

(b) The manufactured gas plant represents the current liability for remediation of a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. (See Note 8. Commitments, Guarantees and Contingencies.)

(c) Amount reclassified from Non-Controlling Interest in Subsidiaries resulting from the exercise of an option to buy out a non-controlling interest, which was paid in the first quarter of 2022.

Other Non-Current Liabilities
As of December 31	2021	2020
Millions
Asset Retirement Obligation	$184.5	$166.6
PSAs	39.5	52.1
Operating Lease Liabilities	11.6	16.5
Other	45.2	50.1
Total Other Non-Current Liabilities	$280.8	$285.3

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Leases.

We determine if a contract is, or contains, a lease at inception and recognize a right-of-use asset and lease liability for all leases with a term greater than 12 months. Our right-of-use assets and lease liabilities for operating leases are included in Other Non-Current Assets, Other Current Liabilities and Other Non-Current Liabilities, respectively, in our Consolidated Balance Sheet. We currently do not have any finance leases.

Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and lease liabilities are recognized at the commencement date based on the estimated present value of lease payments over the lease term. As our leases do not provide an explicit rate, we determine the present value of future lease payments based on our estimated incremental borrowing rate using information available at the lease commencement date. The operating lease right-of-use asset includes lease payments to be made during the lease term and any lease incentives, as applicable.

Our leases may include options to extend or buy out the lease at certain points throughout the term, and if it is reasonably certain at lease commencement that we will exercise that option, we include those rental payments in our calculation of the right-of-use asset and lease liability. Lease and rent expense is recognized on a straight-line basis over the lease term. Leases with a term of 12 months or less are not recognized on the Consolidated Balance Sheet.

The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the dragline at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $3 million and is included in our calculation of the right-of-use asset and lease liability recorded. None of our other leases contain residual value guarantees.

Additional information on the components of lease cost and presentation of cash flows were as follows:

As December 31	2021	2020
Millions
Operating Lease Cost	$6.7	$8.3
Other Information:
Operating Cash Flows From Operating Leases	$6.7	$8.3

Additional information related to leases was as follows:

As of December 31	2021		2020
Millions
Balance Sheet Information Related to Leases:
Other Non-Current Assets	$16.4		$22.4
Total Operating Lease Right-of-use Assets	$16.4		$22.4
Other Current Liabilities	$4.8		$5.9
Other Non-Current Liabilities	11.6		16.5
Total Operating Lease Liabilities	$16.4		$22.4
Weighted Average Remaining Lease Term (Years):
Operating Leases - Vehicles and Equipment	3		3
Operating Leases - Land and Other	27		27
Weighted Average Discount Rate:
Operating Leases - Vehicles and Equipment	3.8	%	3.1	%
Operating Leases - Land and Other	4.5	%	4.1	%

ALLETE, Inc. 2021 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Leases (Continued)

Maturities of lease liabilities were as follows:

	December 31, 2021
Millions
2022	$5.1
2023	3.3
2024	3.0
2025	2.8
2026	2.8
Thereafter	5.0
Total Lease Payments Due	22.0
Less: Imputed Interest	5.6
Total Lease Obligations	16.4
Less: Current Lease Obligations	4.8
Total Long-term Lease Obligations	$11.6

Environmental Liabilities. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. (See Note 8. Commitments, Guarantees and Contingencies.)

Revenue.

Contracts with Customers – Utility includes sales from our regulated operations for generation, transmission and distribution of electric service, and distribution of water and gas services to our customers. Also included is an immaterial amount of regulated steam generation that is used by customers in the production of paper and pulp.

Contracts with Customers – Non-utility includes sales of goods and services to customers from ALLETE Clean Energy, U.S. Water Services and our Corporate and Other businesses.

Other – Non-utility is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices for PSAs that were assumed during the acquisition of various wind energy facilities.

Revenue Recognition. Revenue is recognized upon transfer of control of promised goods or services to our customers in an amount that reflects the consideration we expect to receive in exchange for those products or services. Revenue is recognized net of allowance for returns and any taxes collected from customers, which are subsequently remitted to the appropriate governmental authorities. We account for shipping and handling activities that occur after the customer obtains control of goods as a cost rather than an additional performance obligation thereby recognizing revenue at time of shipment and accruing shipping and handling costs when control transfers to our customers. We have a right to consideration from our customers in an amount that corresponds directly with the value to the customer for our performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Nature of Revenue Streams

Utility

Residential and Commercial includes sales for electric, gas or water service to customers, who have implied contracts with the utility, under rates governed by the MPUC, PSCW or FERC. Customers are billed on a monthly cycle basis and revenue is recognized for electric, gas or water service delivered during the billing period. Revenue is accrued for service provided but not yet billed at period end. Performance obligations with these customers are satisfied at time of delivery to customer meters and simultaneously consumed.

Municipal includes sales to 15 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. All wholesale electric contracts include a termination clause requiring a three-year notice to terminate. These contracts have termination dates ranging through 2037, with a majority of contracts effective through 2029. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon municipal substation or meter.

Industrial includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 47 percent of total regulated utility kWh sales for the year ended December 31, 2021. Within industrial revenue, Minnesota Power had eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2021. These contracts automatically renew past the contract term unless a four-year advanced written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2025 through 2029. In January 2021, Verso Corporation provided notice of termination for its contract. Minnesota Power and Verso Corporation mutually agreed to resolve the outstanding commitments under the contract in January 2022. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $50 million per annum through 2025, $15 million in 2026, and $30 million in total thereafter, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts.

Other Power Suppliers includes the sale of energy under a long-term PSA with one customer as well as MISO market and liquidation sales. The expiration date of this PSA is 2028. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon delivery point defined in the contract (generally the MISO pricing node). The current contract with one customer contains variable pricing components that prevent us from estimating future minimum revenue.

Other Revenue includes all remaining individually immaterial revenue streams for Minnesota Power and SWL&P, and is comprised of steam sales to paper and pulp mills, wheeling revenue and other sources. Revenue for steam sales to customers is recognized at the time steam is delivered and simultaneously consumed. Revenue is recognized at the time each performance obligation is satisfied.

CIP Financial Incentive reflects certain revenue that is a result of the achievement of certain objectives for our CIP financial incentives. This revenue is accounted for in accordance with the accounting standards for alternative revenue programs which allow for the recognition of revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows for automatic adjustment of future rates, the amount of revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. CIP financial incentives are recognized in the period in which the MPUC approves the filing, which is typically mid-year.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Non-utility

ALLETE Clean Energy

Long-term PSA revenue includes all sales recognized under long-term contracts for production, curtailment, capacity and associated renewable energy credits from ALLETE Clean Energy wind energy facilities. Expiration dates of these PSAs range from 2022 through 2039. Performance obligations for these contracts are satisfied at the time energy is delivered to an agreed upon point, or production is curtailed at the request of the customer, at specified prices. Revenue from the sale of renewable energy credits is recognized at the same time the related energy is delivered to the customer when sold to the same party.

Sale of Wind Energy Facility includes revenue recognized for the design, development, construction, and sale of a wind energy facility to a customer. Performance obligations for these types of agreements are satisfied at the time the completed project is transferred to the customer at the commercial operation date. Revenue from the sale of a wind energy facility is recognized at the time of asset transfer.

Other is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of wind energy facility acquisitions, ALLETE Clean Energy assumed various PSAs that were above or below estimated market prices at the time of acquisition; the resulting differences between contract prices and estimated market prices are amortized to revenue over the remaining PSA term.

U.S. Water Services

In 2019, ALLETE completed the sale of U.S. Water Services. Prior to the sale, ALLETE recognized revenue under the point-in-time, contract and capital project streams. Point-in-time revenue was recognized for purchases by customers for chemicals, consumable equipment or related maintenance and repair services as the customer’s usage and needs changed over time. Contract revenue included monthly revenue from contracts with customers to provide chemicals, consumable equipment and services to meet customer needs during the contract period at a fixed monthly price. Capital Project revenue was recognized at the time of sale when equipment and other components were assembled to create a water treatment system for a customer.

Corporate and Other

Long-term Contract encompasses the sale and delivery of coal to customer generation facilities. Revenue is recognized on a monthly basis at the cost of production plus a specified profit per ton of coal delivered to the customer. Coal sales are secured under long-term coal supply agreements extending through 2037. Performance obligations are satisfied during the period as coal is delivered to customer generation facilities.

Other primarily includes revenue from BNI Energy unrelated to coal, the sale of real estate from ALLETE Properties, and non‑rate base steam generation that is sold for use during production of paper and pulp. Performance obligations are satisfied when control transfers to the customer.

Payment Terms

Payment terms and conditions vary across our businesses. Aside from taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customers’ energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite-producing Large Power Customers have generally predictable energy usage on a weekly basis and any differences that occur are trued-up the following month. Due to the timing difference of revenue recognition from the timing of invoicing and payment, the taconite-producing Large Power Customers receive credit for the time value of money; however, we have determined that our contracts do not include a significant financing component as the period between when we transfer the service to the customer and when they pay for such service is minimal.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Assets Recognized From the Costs to Obtain a Contract with a Customer

We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2021, we have $23.3 million of assets recognized for costs incurred to obtain contracts with our customers ($25.5 million as of December 31, 2020). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $2.7 million of non-cash amortization for the year ended December 31, 2021 ($2.6 million for the year end December 31, 2020).

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using a method which approximates the effective interest method.

Tax Equity Financings. Certain subsidiaries of ALLETE have entered into tax equity financings that include forming limited liability companies (LLC) with third-party investors for certain wind projects. Tax equity financings have specific terms that dictate distributions of cash and the allocation of tax attributes among the LLC members, who are divided into two categories: the sponsor and third-party investors. ALLETE subsidiaries are the sponsors in these tax equity financings. The distributions of cash and allocation of tax attributes in these financings generally differ from the underlying percentage ownership interests in the related LLC, with a disproportionate share of tax attributes (including accelerated depreciation and production tax credits) allocated to third-party investors in order to achieve targeted after-tax rates of return, or target yield, from project operations, and a disproportionate share of cash distributions made to the sponsor.

The target yield and other terms vary by tax equity financing. Once the target yield has been achieved, a “flip point” is recognized. In addition, tax equity financings typically provide that cash distributions can be temporarily increased to the third-party investors in order to meet cumulative distribution thresholds. After the flip point, tax attributes and cash distributions are both typically disproportionately allocated to the sponsor.

Tax equity financings include affirmative and negative covenants that are similar to what a project lender would require in a project financing, such as financial reporting, insurance, maintenance and prudent operator standards. Most covenants are no longer applicable once the flip point occurs and any other obligations of the third-party investor have been eliminated.

The third-party investors’ portions of equity ownership in tax equity LLCs are recorded as non-controlling interest in subsidiaries on the Consolidated Balance Sheet and earnings allocated to third-party investors are recorded as net loss attributable to non-controlling interest on the Consolidated Statement of Income.

Non-Controlling Interest in Subsidiaries. Non-controlling interest in subsidiaries represents the portion of equity ownership, net income (loss), and comprehensive income (loss) in subsidiaries that is not attributable to equity holders of ALLETE. These amounts as of and for the years ended December 31, 2021 and 2020, related to the tax equity financings for ALLETE Clean Energy’s 106 MW Glen Ullin, 80 MW South Peak, 303 MW Diamond Spring and 303 MW Caddo wind energy facilities as well as ALLETE’s equity investment in the 250 MW Nobles 2 wind energy facility.

For those wind projects with tax equity financings where the economic benefits are not allocated based on the underlying ownership percentage interests, we have determined that the appropriate methodology for calculating the non-controlling interest in subsidiaries balance is the hypothetical liquidation at book value (HLBV) method. The HLBV method is a balance sheet approach which reflects the substantive economic arrangements in the tax equity financing structures.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Non-Controlling Interest in Subsidiaries (Continued)

Under the HLBV method, amounts reported as non-controlling interest in subsidiaries on the Consolidated Balance Sheet represent the amounts the third-party investors would hypothetically receive at each balance sheet reporting date under the liquidation provisions of the LLC agreements, assuming the net assets of the wind projects were liquidated at amounts determined in accordance with GAAP and distributed to the third-party investor and sponsor. The resulting non-controlling interest in subsidiaries balance in these projects is reported as a component of equity on the Consolidated Balance Sheet.

The results of operations for these projects attributable to non-controlling interest under the HLBV method is determined as the difference in non-controlling interest in subsidiaries on the Consolidated Balance Sheet at the start and end of each reporting period, after taking into account any capital transactions between the projects and the third-party investors.

Factors used in the HLBV calculation include GAAP income, taxable income (loss), tax attributes such as accelerated depreciation and production tax credits, capital contributions, cash distributions, and the target yield specified in the corresponding LLC agreement. Changes in these factors could have a significant impact on the amounts that third-party investors and sponsors would receive upon a hypothetical liquidation. The use of the HLBV method to allocate income to the non-controlling interest in subsidiaries may create variability in our results of operations as the application of the HLBV method can drive variability in net income or loss attributable to non-controlling interest in subsidiaries from period to period.

Other Income (Expense) - Other
Year Ended December 31	2021	2020	2019
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credit (a)	$6.1	$8.6	$7.7
Interest and Investment Earnings	2.3	1.6	4.4
AFUDC - Equity	2.6	1.9	2.3
Gain on Land Sales	0.1	0.4	2.1
Other	(2.4)	2.2	2.2
Total Other Income (Expense) - Other	$8.7	$14.7	$18.7

(a)These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 11. Pension and Other Postretirement Benefit Plans.)

Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns. We account for income taxes using the liability method in accordance with GAAP for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable.

Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with GAAP for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more‑likely‑than‑not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more‑likely‑than‑not” means more than 50 percent likely. (See Note 10. Income Tax Expense.)

Excise Taxes. We collect excise taxes from our customers levied by governmental entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the governmental entity. We account for the collection and payment of these taxes on a net basis.

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NOTE 2. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31	2021	2020
Millions
Regulated Operations
Property, Plant and Equipment in Service	$5,028.7	$4,972.3
Construction Work in Progress	108.7	79.4
Accumulated Depreciation	(1,834.6)	(1,758.0)
Regulated Operations – Net	3,302.8	3,293.7
ALLETE Clean Energy
Property, Plant and Equipment in Service	1,716.9	1,275.4
Construction Work in Progress	79.9	261.0
Accumulated Depreciation	(149.0)	(112.9)
ALLETE Clean Energy – Net	1,647.8	1,423.5
Corporate and Other (a)
Property, Plant and Equipment in Service	267.1	240.5
Construction Work in Progress	19.8	9.6
Accumulated Depreciation	(137.3)	(126.5)
Corporate and Other – Net	149.6	123.6
Property, Plant and Equipment – Net	$5,100.2	$4,840.8

(a)Primarily includes BNI Energy and a small amount of non-rate base generation.

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.

Estimated Useful Lives of Property, Plant and Equipment (Years)
Regulated Operations
Generation	2 to 50	ALLETE Clean Energy	5 to 35
Transmission	50 to 75	Corporate and Other	3 to 50
Distribution	18 to 70

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NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long‑lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (AROs) relate primarily to the decommissioning of our coal-fired and wind energy facilities, and land reclamation at BNI Energy. AROs are included in Other Non-Current Liabilities on the Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.

Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, the period of remediation is indeterminable and removal liabilities have not been recognized.

Long-standing ratemaking practices approved by applicable state and federal regulatory authorities have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-AROs. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with GAAP for AROs. (See Note 4. Regulatory Matters.)

Asset Retirement Obligations
Millions
Obligation as of December 31, 2019	$160.3
Accretion	8.3
Liabilities Recognized	1.4
Liabilities Settled	(3.6)
Revisions in Estimated Cash Flows	0.2
Obligation as of December 31, 2020	166.6
Accretion	8.8
Liabilities Recognized	4.5
Liabilities Settled	(5.2)
Revisions in Estimated Cash Flows	9.8
Obligation as of December 31, 2021	$184.5

NOTE 3. JOINTLY-OWNED FACILITIES AND ASSETS

Boswell Unit 4. Minnesota Power owns 80 percent of the 585 MW Boswell Unit 4. While Minnesota Power operates the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which it and WPPI Energy, the owner of the remaining 20 percent, have equal representation and voting rights. Each owner must provide its own financing and is obligated to its ownership share of operating costs. Minnesota Power’s share of operating expenses for Boswell Unit 4 is included in Operating Expenses on the Consolidated Statement of Income.

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NOTE 3. JOINTLY-OWNED FACILITIES AND ASSETS (Continued)

Minnesota Power’s investments in jointly-owned facilities and assets and the related ownership percentages are as follows:

Regulated Utility Plant	Plant in Service	Accumulated Depreciation	Construction Work in Progress	% Ownership
Millions
As of December 31, 2021
Boswell Unit 4	$682.7	$311.1	$30.1	80
Transmission Assets	101.0	18.5	—	9.3 - 14.7
Total	$783.7	$329.6	$30.1
As of December 31, 2020
Boswell Unit 4	$663.8	$288.8	$15.0	80
Transmission Assets	101.0	16.0	—	9.3 - 14.7
Total	$764.8	$304.8	$15.0

NOTE 4. REGULATORY MATTERS

Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider, Solar Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $38.9 million in 2021 ($29.9 million in 2020; $31.8 million in 2019).

2020 Minnesota General Rate Case. In November 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing sought a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $66 million in additional revenue. In December 2019 orders, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $36.1 million beginning January 1, 2020.

In April 2020, Minnesota Power filed a request with the MPUC that proposed a resolution of Minnesota Power’s 2020 general rate case. Key components of our proposal included removing the power marketing margin credit in base rates and reflecting actual power marketing margins in the fuel adjustment clause effective May 1, 2020; refunding to customers interim rates collected through April 2020; increasing customer rates 4.1 percent compared to the 5.8 percent increase reflected in interim rates; and a provision that Minnesota Power would not file another rate case until at least November 1, 2021, unless certain events occur. In a June 2020 order, the MPUC approved Minnesota Power’s petition and proposal to resolve and withdraw the general rate case. Effective May 1, 2020, customer rates were set at an increase of 4.1 percent with the removal of the power marketing margin credit from base rates. Actual power marketing margins will be reflected in the fuel adjustment clause. Reserves for interim rates of $11.7 million were recorded in the second quarter of 2020 and refunded in the third and fourth quarters of 2020.

2022 Minnesota General Rate Case. On November 1, 2021, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 18 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $108 million in additional revenue. In orders dated December 30, 2021, the MPUC accepted the filing as complete and authorized an annual interim rate increase beginning January 1, 2022, with approximately $80 million expected to be collected in cash and approximately $8 million of interim rates for residential customers deferred with a final determination on recovery at the end of the rate case.

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NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Minnesota Power Land Sales. In August 2020, Minnesota Power filed a petition with the MPUC for approval to sell land that surrounds several reservoirs on its hydroelectric system and is no longer required to maintain its operations. The land has an estimated value of approximately $100 million, and Minnesota Power proposed to credit ratepayers the net proceeds from the sales in a future rate case or through its renewable resources rider to mitigate future rate increases. In an order dated November 18, 2021, the MPUC authorized the land sales and directed the net proceeds to be refunded to ratepayers subject to certain conditions and required compliance filings.

FERC-Approved Wholesale Rates. Minnesota Power has wholesale contracts with 15 non-affiliated municipal customers in Minnesota and SWL&P. Three of the wholesale contracts include a termination clause requiring a three-year notice to terminate.

Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission was extended in October 2020 and is effective through December 31, 2037. The wholesale electric service contract with SWL&P is effective through February 28, 2025. Under the agreement with SWL&P, no termination notice has been given. The rates included in these two contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.

Minnesota Power’s wholesale electric contracts with 13 other municipal customers were extended in January 2022 and are effective through 2029. These contracts are based on fixed prices for capacity and energy. The base energy charge for each year is adjusted annually for updated fuel and purchased power costs. The wholesale electric contract with one other municipal customer is effective through 2024. The capacity charge is determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term is set each January 1, subject to monthly adjustment, and is determined using a cost-based formula methodology.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place to charge retail customers on a current basis for certain transmission investments and expenditures, including a return on the capital invested. Current customer billing rates are based on a December 2020 order. In December 2020, Minnesota Power filed a petition seeking MPUC approval to update customer billing rates for additional investments made for the GNTL. On December 28, 2021, Minnesota Power submitted its annual factor filing seeking MPUC approval to further update customer billing rates under the transmission cost recovery rider.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place to charge retail customers on a current basis for the costs of certain renewable investments and expenditures, including a return on the capital invested. Current customer billing rates for the renewable cost recovery rider were approved by the MPUC in a December 2020 order. On February 2, 2022, Minnesota Power submitted its 2022 renewable factor filing. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

Solar Cost Recovery Rider. In June 2020, Minnesota Power filed a petition seeking MPUC approval of a customer billing rate for solar costs related to investments and expenditures for meeting the state of Minnesota’s solar energy standard, which was approved by the MPUC in an order dated April 20, 2021. New customer billing rates for the solar cost recovery rider were implemented on June 1, 2021. On October 21, 2021, Minnesota Power submitted its 2022 solar factor filing. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a November 2018 order. On January 19, 2021, Minnesota Power filed a petition seeking MPUC approval to end the environmental improvement rider, which was approved in an order dated April 20, 2021. The environmental improvement rider ended effective October 1, 2021.

Electric Vehicle Charging Infrastructure Petition. On April 8, 2021, Minnesota Power filed a petition seeking approval to install and own DC fast charger stations for electric vehicles across its service territory, implement accompanying rates for those stations, and track and recover investments and expenses for the project. In an order dated October 22, 2021, the MPUC approved Minnesota Power’s petition.

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NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Fuel Adjustment Clause. The costs of fuel and related transportation costs for Minnesota Power’s generation as well as costs of purchased power for Minnesota Power are recoverable from Minnesota Power’s utility retail customers through the fuel adjustment clause (FAC). The FAC for Minnesota electric utilities is a monthly budgeted, forward-looking process with annual prudence review and true-up to actual allowed costs. In May 2020, Minnesota Power filed its fuel adjustment forecast for 2021, which was approved by the MPUC in a December 2020 order, subject to the annual prudence review and true-up filing in 2022. During 2021, Minnesota Power incurred higher fuel and purchased power costs than those forecasted in its May 2020 filing, which resulted in the recognition of an approximately $56 million regulatory asset as of December 31, 2021. Minnesota Power will make its annual true-up filing and a significant events filing in March 2022 requesting recovery of these under-collected fuel adjustment clause recoveries.

In March 2020, Minnesota Power filed its FAC report covering the period July 2018 through December 2019. In a September 2020 order, the MPUC referred the review of Minnesota Power’s forced outage costs during the period of the report, which totaled approximately $8 million, to an administrative law judge (ALJ) for a contested case hearing to recommend to the MPUC if any of those costs should be returned to customers. On August 11, 2021, the ALJ recommended that Minnesota Power refund approximately $5 million to ratepayers. Minnesota Power submitted exceptions to the ALJ’s report to the MPUC stating that it disagreed with the ALJ’s recommendation and that no refund should be made as the Company operated its facilities in accordance with good utility practice. At a hearing on January 13, 2022, the MPUC agreed with the ALJ’s recommendation and ordered the refund of approximately $5 million to ratepayers, which was recorded as a reserve as of December 31, 2021.

COVID-19 Related Deferred Accounting. In a March 2020 order, the PSCW authorized public utilities, including SWL&P, to defer expenditures incurred by the utility resulting from its compliance with state government or regulator orders during Wisconsin’s declared public health emergency for COVID-19. In a May 2020 order, the MPUC required Minnesota Power along with other regulated electric and natural gas service providers in Minnesota to track cost and revenue impacts resulting from the COVID-19 pandemic with review for recovery in a future rate proceeding. As of December 31, 2021, Minnesota Power has not deferred any costs or lost revenue, and SWL&P has deferred an immaterial amount of costs.

Minnesota Power submitted a petition in November 2020 to the MPUC requesting authority to track and record as a regulatory asset lost large industrial customer revenue resulting from the idling of USS Corporation’s Keetac plant and Verso Corporation’s paper mill in Duluth, Minnesota. In an order dated May 13, 2021, the MPUC denied Minnesota Power’s request.

2018 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a December 2018 order by the PSCW that allows for a return on equity of 10.4 percent and a 55.0 percent equity ratio. The PSCW had directed SWL&P to file its next general rate case in 2020; however, the PSCW granted an extension request made by SWL&P to delay filing its next general rate case until on or before December 20, 2022. SWL&P requested the extension primarily due to impacts of the COVID-19 pandemic.

Integrated Resource Plan. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct requests for proposal for additional wind, solar and demand response resource additions. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018.

2021 Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP with the MPUC, which outlines its clean-energy transition plans through 2035. These plans include expanding its renewable energy supply, achieving coal-free operations at its facilities by 2035, and investing in a resilient and flexible transmission and distribution grid. As part of these plans, Minnesota Power anticipates adding approximately 400 MW of new wind and solar energy resources, retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Minnesota Power’s plans recognize that advances in technology will play a significant role in completing its transition to carbon-free energy supply, reliably and affordably. A final decision on the IRP is expected in the second half of 2022.

ALLETE, Inc. 2021 Form 10-K

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NOTE 4. REGULATORY MATTERS (Continued)

Nemadji Trail Energy Center. In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of a natural gas capacity dedication and other affiliated-interest agreements for NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to the capacity dedication agreement. (See Note 1. Operations and Significant Accounting Policies.) In a January 2019 order, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication and other affiliated-interest agreements. In 2019, the Minnesota Court of Appeals reversed and remanded the MPUC’s decision to approve certain affiliated-interest agreements. On April 21, 2021, the Minnesota Supreme Court reversed the Minnesota Court of Appeal’s decision by ruling that the MPUC is not required to conduct a review under the Minnesota Environmental Policy Act before approving affiliated-interest agreements that govern construction and operation of a Wisconsin power plant by a Minnesota utility, and remanded the case back to the Minnesota Court of Appeals for review of remaining issues on appeal. On August 23, 2021, the Minnesota Court of Appeals affirmed the decision by the MPUC to approve certain affiliated-interest agreements.

Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on energy CIPs each year.

On April 1, 2021, Minnesota Power submitted its 2020 consolidated filing detailing Minnesota Power’s CIP program results and requesting a CIP financial incentive of $2.4 million based upon MPUC procedures, which was recognized in the third quarter of 2021 upon approval by the MPUC in an order dated September 7, 2021. In 2020, a CIP financial incentive of $2.4 million was recognized in the third quarter upon approval by the MPUC of Minnesota Power’s 2019 CIP consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

In July 2020, Minnesota Power submitted its CIP triennial filing for 2021 through 2023 to the MPUC and Minnesota Department of Commerce, which outlines Minnesota Power’s CIP spending and energy-saving goals for those years. Minnesota Power’s CIP investment goals are $10.7 million for 2022 and $10.9 million for 2023.

MISO Return on Equity Complaint. MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of 10.02 percent, or 10.52 percent including an incentive adder for participation in a regional transmission organization based on a 2020 FERC order that granted rehearing of a 2019 FERC order. These FERC orders are subject to various outstanding legal challenges related to the refund period ordered by the FERC.

Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. Minnesota Power has met both parts of the solar mandate to date.

In May 2020, the MPUC issued a notice requesting all regulated gas and electric utilities provide a list of all ongoing, planned, or possible investments that support Minnesota’s energy policy objectives and aid economic recovery in Minnesota, among other items. In June 2020, Minnesota Power filed proposal with the MPUC to accelerate its plans for purchasing solar energy from approximately 20 MW of solar energy projects in Minnesota which was approved in a June 2021 order. These solar energy projects will be constructed and owned through an ALLETE subsidiary with an estimated investment of $40 million. Construction of these solar energy projects is expected to commence in 2022.

Regulatory Assets and Liabilities. Our regulated utility operations are subject to accounting standards for the effects of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

ALLETE, Inc. 2021 Form 10-K

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NOTE 4. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
As of December 31	2021	2020
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (a)	$226.4	$259.7
Income Taxes (b)	104.7	113.7
Cost Recovery Riders (c)	63.2	54.0
Fuel Adjustment Clause (d)	56.4	—
Asset Retirement Obligations (e)	33.1	31.6
Manufactured Gas Plant (f)	17.0	8.8
PPACA Income Tax Deferral	4.3	4.5
Conservation Improvement Program (g)	2.4	—
Boswell Units 1 and 2 Net Plant and Equipment (h)	—	5.0
Other	4.3	3.6
Total Non-Current Regulatory Assets	$511.8	$480.9
Current Regulatory Liabilities (i)
Fuel Adjustment Clause (d)	$5.0	$3.7
Transmission Formula Rates	3.1	2.9
Other	0.5	1.0
Total Current Regulatory Liabilities	8.6	7.6
Non-Current Regulatory Liabilities
Income Taxes (b)	353.4	375.3
Wholesale and Retail Contra AFUDC (j)	83.7	86.6
Plant Removal Obligations (k)	52.6	41.2
Defined Benefit Pension and Other Postretirement Benefit Plans (a)	28.1	4.4
North Dakota Investment Tax Credits (l)	12.2	12.0
Boswell Units 1 and 2 Net Plant and Equipment (h)	0.4	—
Conservation Improvement Program (g)	—	1.5
Other	5.7	3.8
Total Non-Current Regulatory Liabilities	536.1	524.8
Total Regulatory Liabilities	$544.7	$532.4

(a)Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 11. Pension and Other Postretirement Benefit Plans.)

(b)These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The balances will primarily decrease over the remaining life of the related temporary differences.

(c)The cost recovery rider regulatory assets and liabilities are revenue not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, the Boswell Unit 4 environmental upgrade and the GNTL as well as differences between production tax credits recognized and those assumed in Minnesota Power’s base rates. The cost recovery rider regulatory assets as of December 31, 2021, will be recovered within the next two years.

(d)Fuel adjustment clause regulatory asset and liability represent the amount expected to be recovered from or refunded to customers for the under- or over-collection of fuel adjustment clause recoveries. (See Fuel Adjustment Clause.)

(e)Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.

(f)The manufactured gas plant regulatory asset represents costs of remediation for a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. We expect recovery of these remediation costs to be allowed by the PSCW in rates over time.

(g)The conservation improvement program regulatory liability represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future refund over the next year following MPUC approval.

(h)In 2018, Minnesota Power retired Boswell Units 1 and 2 and reclassified the remaining net book value from property, plant and equipment to a regulatory asset on the Consolidated Balance Sheet. The remaining net book value is currently included in Minnesota Power’s rate base and Minnesota Power is earning a return on the outstanding balance.

(i)Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.

(j)Wholesale and retail contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.

(k)Non-legal plant removal obligations included in retail customer rates that have not yet been incurred.

(l)North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s retail customers through future renewable cost recovery rider filings as the tax credits are utilized.

ALLETE, Inc. 2021 Form 10-K

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NOTE 5. EQUITY INVESTMENTS

Investment in ATC. Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. On January 31, 2022, we invested an additional $2.7 million in ATC. In total, we expect to invest approximately $6.0 million in 2022.

ALLETE’s Investment in ATC
Year Ended December 31	2021	2020
Millions
Equity Investment Beginning Balance	$149.0	$141.6
Cash Investments	—	2.7
Equity in ATC Earnings	21.3	22.3
Distributed ATC Earnings	(17.2)	(18.9)
Amortization of the Remeasurement of Deferred Income Taxes	1.4	1.3
Equity Investment Ending Balance	$154.5	$149.0

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2021	2020
Millions
Current Assets	$89.8	$92.8
Non-Current Assets	5,628.1	5,400.5
Total Assets	$5,717.9	$5,493.3
Current Liabilities	$436.9	$310.8
Long-Term Debt	2,513.0	2,512.2
Other Non-Current Liabilities	422.0	378.2
Members’ Equity	2,346.0	2,292.1
Total Liabilities and Members’ Equity	$5,717.9	$5,493.3

Income Statement Data
Year Ended December 31	2021	2020	2019
Millions
Revenue	$754.8	$758.1	$744.4
Operating Expense	376.2	372.4	373.5
Other Expense	113.9	110.9	110.5
Net Income	$264.7	$274.8	$260.4
ALLETE’s Equity in Net Income	$21.3	$22.3	$21.7

ATC’s authorized return on equity is 10.02 percent, or 10.52 percent including an incentive adder for participation in a regional transmission organization, based on a 2020 FERC order that granted rehearing of a 2019 FERC order. These FERC orders are subject to various outstanding legal challenges related to the refund period ordered by the FERC. If these legal challenges are successful, ATC may be required to provide refunds to its customers of up to approximately $65 million of which our share would be approximately $5 million pre-tax. In addition, the FERC issued a Notice of Proposed Rulemaking in April 2021 proposing to limit the 50 basis point incentive adder for participation in a regional transmission organization to only the first three years of membership in such an organization. If this proposal is adopted, our equity in earnings from ATC would be reduced by approximately $1 million pre-tax annually.

ALLETE, Inc. 2021 Form 10-K

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NOTE 5. EQUITY INVESTMENTS (Continued)

Investment in Nobles 2. Our subsidiary, ALLETE South Wind, owns a 49 percent equity interest in Nobles 2, the entity that owns and operates a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. We account for our investment in Nobles 2 under the equity method of accounting.

ALLETE’s Investment in Nobles 2
Millions
Equity Investment Balance as of December 31, 2020	$152.2
Cash Investments	17.6
Equity in Nobles 2 Earnings (a)	(1.3)
Distributed Nobles 2 Earnings	(5.0)
Equity Investment Balance as of December 31, 2021	$163.5

(a)The Company also recorded net loss attributable to non-controlling interest of $6.6 million related to its investment in Nobles 2.

NOTE 6. FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily equity securities.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. This category includes deferred compensation and fixed income securities.

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value.

ALLETE, Inc. 2021 Form 10-K

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NOTE 6. FAIR VALUE (Continued)

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021, and December 31, 2020. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.

	Fair Value as of December 31, 2021
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities	$8.9	—	—	$8.9
Available-for-sale – Corporate and Governmental Debt Securities (b)	—	$6.2	—	6.2
Cash Equivalents	2.5	—	—	2.5
Total Fair Value of Assets	$11.4	$6.2	—	$17.6
Liabilities:
Deferred Compensation (c)	—	$18.0	—	$18.0
Total Fair Value of Liabilities	—	$18.0	—	$18.0
Total Net Fair Value of Assets (Liabilities)	$11.4	$(11.8)	—	$(0.4)

(a)Included in Other Non-Current Assets on the Consolidated Balance Sheet.

(b)As of December 31, 2021, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.0 million, in one year to less than three years was $2.3 million, in three years to less than five years was $2.1 million and in five or more years was $0.8 million.

(c)Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

	Fair Value as of December 31, 2020
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities	$7.2	—	—	$7.2
Available-for-sale – Corporate and Governmental Debt Securities	—	$10.4	—	10.4
Cash Equivalents	5.5	—	—	5.5
Total Fair Value of Assets	$12.7	$10.4	—	$23.1
Liabilities: (b)
Deferred Compensation	—	$21.0	—	$21.0
Total Fair Value of Liabilities	—	$21.0	—	$21.0
Total Net Fair Value of Assets (Liabilities)	$12.7	$(10.6)	—	$2.1

(a)Included in Other Non-Current Assets on the Consolidated Balance Sheet.

(b)Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

The Company’s policy is to recognize transfers in and transfers out of Levels as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 2021 and 2020, there were no transfers in or out of Levels 1, 2 or 3.

Fair Value of Financial Instruments. With the exception of the item listed in the following table, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed in the following table was based on quoted market prices for the same or similar instruments (Level 2).

ALLETE, Inc. 2021 Form 10-K

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NOTE 6. FAIR VALUE (Continued)

Financial Instruments	Carrying Amount	Fair Value
Millions
Short-Term and Long-Term Debt (a)
December 31, 2021	$1,986.4	$2,192.6
December 31, 2020	$1,806.4	$2,122.0

(a) Excludes unamortized debt issuance costs.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.

Equity Method Investments. The aggregate carrying amount of our equity investments was $318.0 million as of December 31, 2021 ($301.2 million as of December 31, 2020). The Company assesses our equity investments in ATC and Nobles 2 for impairment whenever events or changes in circumstances indicate that the carrying amount of our investments may not be recoverable. For the years ended December 31, 2021 and 2020, there were no indicators of impairment. (See Note 5. Equity Investments.)

Property, Plant and Equipment. The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable. (See Note 1. Operations and Significant Accounting Policies.) For the years ended December 31, 2021, and 2020, there was no impairment of property, plant, and equipment.

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. Minnesota Power’s 2015 IRP contained steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in 2016, and the ceasing of coal-fired operations at Taconite Harbor in 2020. As of December 31, 2021, Taconite Harbor had a net book value of approximately $45 million. The MPUC order for the 2015 IRP also directed Minnesota Power to retire Boswell Units 1 and 2, which occurred in the fourth quarter of 2018. As part of the 2016 general retail rate case, the MPUC allowed recovery of the remaining book value of Boswell Units 1 and 2 through 2022. In its latest IRP filing, Minnesota Power proposed retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Boswell Unit 3 and Unit 4 have a net book value of approximately $245 million and $435 million, respectively, as of December 31, 2021. (See Note 4. Regulatory Matters.) We do not expect to record any impairment charge as a result of these operating changes at Taconite Harbor and Boswell. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives.

NOTE 7. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2021, total short-term debt outstanding was $214.2 million ($203.7 million as of December 31, 2020), and consisted of long-term debt due within one year and included $0.2 million of unamortized debt issuance costs.

As of December 31, 2021, we had consolidated bank lines of credit aggregating $432.0 million ($407.0 million as of December 31, 2020), most of which expire in January 2025. We had $31.5 million outstanding in standby letters of credit and $159.7 million outstanding draws under our lines of credit as of December 31, 2021 ($22.3 million in standby letters of credit and no outstanding draws as of December 31, 2020).

ALLETE, Inc. 2021 Form 10-K

94

NOTE 7. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt. As of December 31, 2021, total long-term debt outstanding was $1,763.2 million ($1,593.2 million as of December 31, 2020) and included $8.8 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2022 is $214.5 million; $89.7 million in 2023; $74.4 million in 2024; $386.7 million in 2025; $77.2 million in 2026; and $1,143.9 million thereafter. Substantially all of our regulated electric plant is subject to the lien of the mortgages collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

Minnesota Power is obligated to make financing payments for the Camp Ripley solar array totaling $1.4 million annually during the financing term, which expires in 2027. Minnesota Power has the option at the end of the financing term to renew for a two‑year term, or to purchase the solar array for approximately $4 million. Minnesota Power anticipates exercising the purchase option when the term expires.

On March 25, 2021, ALLETE entered into a $150 million unsecured term loan agreement (Term Loan). An additional draw of $35 million through the exercise of an accordion feature was made during the second quarter of 2021. As of September 30, 2021, we have borrowed the full amount of $185 million. The Term Loan is due March 24, 2022, and may be repaid at any time. Interest is payable monthly at a rate per annum equal to LIBOR plus 0.75 percent. Proceeds from the Term Loan were used for general corporate purposes.

On September 1, 2021, ALLETE issued $100 million of its First Mortgage Bonds (Bonds) to certain institutional buyers in the private placement market. The Bonds, which bear interest at 2.79 percent, will mature in September 2031 and pay interest semi-annually in March and September of each year, commencing on March 1, 2022. ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Bonds were used to fund utility capital investment and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

In January 2022, ALLETE Clean Energy received approximately $183.0 million from final closing of tax equity funding for the Caddo wind energy facility. The proceeds from the funding were used to pay down a portion of outstanding draws on our lines of credit.

ALLETE, Inc. 2021 Form 10-K

95

NOTE 7. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt (Continued)

Long-Term Debt
As of December 31	2021	2020
Millions
First Mortgage Bonds
4.85% Series Due 2021	—	$15.0
3.02% Series Due 2021	—	60.0
3.40% Series Due 2022	$75.0	75.0
6.02% Series Due 2023	75.0	75.0
3.69% Series Due 2024	60.0	60.0
4.90% Series Due 2025	30.0	30.0
5.10% Series Due 2025	30.0	30.0
3.20% Series Due 2026	75.0	75.0
5.99% Series Due 2027	60.0	60.0
3.30% Series Due 2028	40.0	40.0
4.08% Series Due 2029	70.0	70.0
3.74% Series Due 2029	50.0	50.0
2.50% Series Due 2030	46.0	46.0
3.86% Series Due 2030	60.0	60.0
2.79% Series Due 2031	100.0	—
5.69% Series Due 2036	50.0	50.0
6.00% Series Due 2040	35.0	35.0
5.82% Series Due 2040	45.0	45.0
4.08% Series Due 2042	85.0	85.0
4.21% Series Due 2043	60.0	60.0
4.95% Series Due 2044	40.0	40.0
5.05% Series Due 2044	40.0	40.0
4.39% Series Due 2044	50.0	50.0
4.07% Series Due 2048	60.0	60.0
4.47% Series Due 2049	30.0	30.0
3.30% Series Due 2050	94.0	94.0
ALLETE Clean Energy Unsecured Term Loan Variable Rate Due 2021	—	65.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024	29.1	38.6
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8	27.8
Revolving Credit Facility Variable Rate Due 2025	145.0	—
Senior Unsecured Notes 2.65% Due 2025	150.0	150.0
Senior Unsecured Notes 3.11% Due 2027	80.0	80.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0	15.0
SWL&P First Mortgage Bonds 4.14% Series Due 2048	12.0	12.0
Unsecured Term Loan Variable Rate Due 2021	—	40.0
Unsecured Term Loan Variable Rate Due 2022	110.0	—
Other Long-Term Debt, 2.16% – 4.58% Due 2022 – 2051	57.5	43.0
Unamortized Debt Issuance Costs	(9.0)	(9.5)
Total Long-Term Debt	1,977.4	1,796.9
Less: Due Within One Year	214.2	203.7
Net Long-Term Debt	$1,763.2	$1,593.2

ALLETE, Inc. 2021 Form 10-K

96

NOTE 7. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt (Continued)

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of December 31, 2021, our ratio was approximately 0.41 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of December 31, 2021, ALLETE was in compliance with its financial covenants.

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The following table details the estimated minimum payments for certain long-term commitments:

As of December 31, 2021
Millions	2022	2023	2024	2025	2026	Thereafter
Capital Purchase Obligations	$50.7	$0.1	—	—	—	—
Easements (a)	$8.2	$8.4	$8.4	$8.8	$9.2	$239.7
PPAs (b)	$141.1	$140.7	$133.5	$131.4	$138.3	$1,060.6
Other Purchase Obligations (c)	$58.9	$22.5	$23.1	—	—	—

(a)Easement obligations represent the minimum payments for our land easement agreements at our wind energy facilities.

(b)Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; or the Oliver Wind I, Oliver Wind II or Nobles 2 PPAs, as Minnesota Power only pays for energy as it is delivered. (See Power Purchase Agreements.)

(c)Consists of long-term service agreements for wind energy facilities and minimum purchase commitments under coal and rail contracts.

Power Purchase and Sales Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments.

These agreements have also been evaluated under the accounting guidance for derivatives. We have determined that either these agreements are not derivatives, or, if they are derivatives, the agreements qualify for the normal purchases and normal sales exception to derivative accounting guidance; therefore, derivative accounting is not required.

Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal‑fired generating unit. Minnesota Power’s output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power PSA described in the following table. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2021, Square Butte had total debt outstanding of $222.6 million. Annual debt service for Square Butte is expected to be approximately $45.5 million annually through 2023, $30.5 million in 2024, $26.6 million in 2025, and $40.1 million in 2026, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.

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97

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power’s cost of power purchased from Square Butte during 2021 was $82.4 million ($79.5 million in 2020; $82.7 million in 2019). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $5.8 million in 2021 ($7.1 million in 2020; $8.3 million in 2019). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnesota Power has also entered into the following long-term PPAs for the purchase of capacity and energy as of December 31, 2021:

Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Calpine Corporation	25 MW	Capacity	June 2019	May 2026	Fixed
Manitoba Hydro
PPA 1	(a)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	250 MW	Capacity / Energy	June 2020	May 2035	(b)
PPA 3	133 MW	Energy	June 2020	June 2040	Forward Market Prices
Nobles 2	250 MW	Capacity / Energy	December 2020	December 2040	Fixed
Oliver Wind I	(c)	Energy	December 2006	December 2040	Fixed
Oliver Wind II	(c)	Energy	December 2007	December 2040	Fixed

(a)The energy purchased consists primarily of surplus hydro energy on Manitoba Hydro's system and is delivered on a non-firm basis. Minnesota Power will purchase at least one million MWh of energy over the contract term.

(b)The capacity price was adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

(c)The PPAs provide for the purchase of all output from the 50 MW Oliver Wind I and 48 MW Oliver Wind II wind energy facilities.

Minnesota Power has also entered into the following long-term PSAs for the sale of capacity and energy as of December 31, 2021:

Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PSAs
Basin
PSA 1	(a)	Capacity	June 2022	May 2025	Fixed
PSA 2	100 MW	Capacity	June 2025	May 2028	Fixed
Great River Energy	100 MW	Capacity	June 2022	May 2025	Fixed
Minnkota Power	(b)	Capacity / Energy	June 2014	December 2026	(b)
Oconto Electric Cooperative	25 MW	Capacity / Energy	January 2019	May 2026	Fixed
Silver Bay Power	(c)	Energy	January 2017	December 2031	(d)

(a)The agreement provides for 75 MW of capacity from June 1, 2022, through May 31, 2023, and increases to 125 MW of capacity from June 1, 2023, through May 31, 2025.

(b)Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2021 (28 percent in 2020 and in 2019). (See Square Butte PPA.)

(c)Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which had previously been served predominately through self-generation by Silver Bay Power. Minnesota Power now supplies the full energy requirements for Silver Bay Power.

(d)The energy pricing escalates at a fixed rate annually and is adjusted for changes in a natural gas index.

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98

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2022. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2024. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Environmental Matters.

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s thermal generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the NOX and SO2 allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. The EPA’s CSAPR Update Rule issued on March 15, 2021, to revise the 2016 CSAPR Update does not apply to the state of Minnesota and is therefore not currently projected to affect Minnesota Power’s CSAPR compliance. The State of Minnesota has not been identified in litigation as a culpable upwind emission source to downwind states, and previous EPA air quality modeling has demonstrated that Minnesota is not a significant contributor to downwind air quality attainment challenges. Minnesota Power will continue to monitor ongoing CSAPR rulemakings and compliance implementation.

National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Minnesota Power actively monitors NAAQS developments and compliance costs for existing standards or proposed NAAQS revisions are not currently expected to be material. The EPA is currently reviewing the secondary NAAQS for NOx and SO2, as well as particulate matter. On June 10, 2021, the EPA announced it will reconsider the December 2020 final rule retaining the 2012 particulate matter NAAQS annual standard, with a proposed rulemaking anticipated in late 2022 and final action expected in early 2023. The EPA also stated it would complete reconsideration of the December 2020 Ozone NAAQS by the end of 2023.

ALLETE, Inc. 2021 Form 10-K

99

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased or other changes in temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:

•Expanding renewable power supply for both our operations and the operations of others;

•Providing energy conservation initiatives for our customers and engaging in other demand side management efforts;

•Improving efficiency of our generating facilities;

•Supporting research of technologies to reduce carbon emissions from generating facilities and carbon sequestration efforts;

•Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas‑fired generating facilities;

•Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and

•Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species.

EPA Regulation of GHG Emissions. In 2019, the EPA finalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units. These rulemakings included repealing the Clean Power Plan (CPP) and adopting the Affordable Clean Energy Rule under Section 111(d) of the Clean Air Act (CAA) to regulate CO2 emissions at existing coal-fired power plants. The CPP was first announced as a proposed rule under Section 111(d) of the CAA for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”. The Affordable Clean Energy Rule established emissions guidelines for states to use when developing plans to limit CO2 coal-fired power plants. The EPA also published regulations for the state implementation of the Affordable Clean Energy Rule and other Section 111(d) rules. Affected facilities for Minnesota Power included Boswell Units 3 and 4, and Taconite Harbor Units 1 and 2, which are currently economically idled.

On January 19, 2021, the D.C. Circuit issued an opinion vacating the Affordable Clean Energy Rule and remanded the Affordable Clean Energy Rule back to the EPA for further consideration, consistent with the D.C. Circuit’s finding that the EPA erred in interpreting the CAA, pending rehearing or appeal. Four petitions were subsequently granted for review by the U.S. Supreme Court on October 29, 2021, with a decision expected in mid-2022.

The EPA also indicated that it intends to issue a proposed rule in mid-2022 and a final rule in mid-2023 with a new set of emission guidelines for states to follow in submitting state plans to establish and implement standards of performance for GHG emissions from existing fossil fuel-fired electric generating units. Minnesota Power will continue to monitor any related guidelines and rulemakings issued by the EPA or state regulatory authorities.

On April 22, 2021, the Biden Administration announced a goal to reach 100 percent carbon pollution-free electricity by 2035 as part of the Nationally Determined Contributions pledge, which is part of an international effort to limit global warming. At this time, no specific regulatory pathway to achieve these reductions has been proposed. Minnesota Power will continue to monitor these developments.

Minnesota had already initiated several measures consistent with those called for under the now repealed CPP and vacated Affordable Clean Energy Rule. Minnesota Power continues implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. We are unable to predict the GHG emission compliance costs we might incur as a result of a replacement for the Affordable Clean Energy Rule or other future laws, regulations or administrative policies; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Additionally on January 13, 2021, the EPA issued a rulemaking to apply CO2 emission New Source Performance Standards (NSPS) to new, modified and reconstructed fossil fuel-fired electric generating units under Section 111(b) of the CAA. In April 2021, the EPA requested and was allowed to voluntarily vacate and remand the Significant Contribution Finding determination criteria related to this NSPS. The EPA intends to issue a proposed rule in mid-2022 and a final rule by mid-2023. Minnesota Power is monitoring the NSPS final rule and any further Section 111(b) developments including their potential impact to the Company. The Company’s proposed combined-cycle natural gas-fired generating facility, NTEC, is expected to meet these NSPS requirements.

Water. The Clean Water Act requires NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.

Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsidered the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On October 13, 2020, the EPA published a final ELG Rule allowing re-use of bottom ash transport water in FGD scrubber systems with limited discharges related to maintaining system water balance. The rule sets technology standards and numerical pollutant limits for discharges of bottom ash transport water and FGD wastewater. Compliance deadlines depend on subcategory, with compliance generally required as soon as possible, beginning after October 13, 2021, but no later than December 31, 2025, or December 31, 2028, in some specific cases. The rule also established new subcategories for retiring high-flow and low-utilization units, and established a voluntary incentives program for FGD wastewater. In accordance with the January 2021 Executive Order 13990, the EPA was mandated to conduct a review of actions and polices taken during the prior administration, including the 2020 ELG Rule. On September 14, 2021, the EPA published a notice of availability for preliminary effluent guidelines program plan. In the plan, the EPA confirmed the agency is initiating a rulemaking process to strengthen wastewater pollution limitations from FGD and bottom ash transport water discharges while the 2020 ELG Rule remains in effect. The EPA is expected to publish a proposed rule in the fall of 2022.

The ELG's potential impact on Minnesota Power operations is primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not discharge to surface waters, but may do so in the future. With Boswell’s planned conversion to dry FGD handling and storage, ongoing FGD water generation will be reduced, and the majority of FGD waters will be legacy waters to be dewatered from existing impoundments. Re-use and onsite consumption for the majority of FGD waters is planned at Boswell.

Under the new ELG rule, most bottom ash transport water discharge to surface waters must cease no later than December 31, 2025, except for small discharges needed to retain water balance. The majority of bottom ash transport water will either need to be re-used in a closed-loop process or routed to a FGD scrubber. At Boswell, the bottom ash handling systems are planned to be converted to a dry process, which will eliminate the discharge of bottom ash transport water.

The EPA’s additional reconsideration of legacy wastewater discharge requirements has the potential to reduce timelines for dewatering Boswell’s existing ponds. The EPA has withdrawn its separate action regarding the 2015 leachate and legacy wastewater ELGs and intends to consolidate that reconsideration with the 2020 bottom ash transport water and FGD ELG reconsideration. A proposed rule is expected in late 2022.

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NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

At this time, we estimate that the planned dry conversion of bottom ash handling and storage at Boswell in response to the CCR revisions requiring closure of clay-lined impoundments, as well as other water re-use practices, will reduce or eliminate the need for additional significant compliance costs for ELG bottom ash water and FGD requirements. Compliance costs we might incur related to other ELG waste streams (e.g., legacy leachate) or other potential future water discharge regulations cannot be estimated; however, the costs could be material, including costs associated with wastewater treatment and re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Permitted Water Discharges – Sulfate. In 2017, the MPCA released a draft water quality standard in an attempt to update Minnesota’s existing 10 mg/L sulfate limit for waters used for the production of wild rice with the proposed rulemaking heard before an administrative law judge (ALJ). In 2018, the ALJ rejected significant portions of the proposed rulemaking and the MPCA subsequently withdrew the rulemaking. The existing 10 mg/L limit remains in place, but the MPCA is currently prohibited under state law from listing wild rice waters as impaired or requiring sulfate reduction technology.

In April 2021, the MPCA’s proposed list of impaired waters submitted pursuant to the Clean Water Act was partially rejected by the EPA due to the absence of wild rice waters listed for sulfate impairment. The EPA subsequently proposed a list of 30 wild rice waters in a separate listing process on April 29, 2021, followed by a list of three additional wild rice waters proposed separately on September 1, 2021. A final impaired waters listing is expected to follow, which could subsequently be used to set sulfate limits in discharge permits for power generation facilities and municipal and industrial customers, including paper and pulp facilities, and mining operations. At this time we are unable to determine the specific impacts these developments may have on Minnesota Power operations, if any. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit reports to the EPA.

Coal Ash Management Facilities. Minnesota Power produces the majority of its coal ash at Boswell, with small amounts of ash generated at Hibbard Renewable Energy Center. Ash storage and disposal methods include storing ash in clay-lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use, and trucking ash to state permitted landfills.

Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to be incurred primarily over the next 15 years and be between approximately $65 million and $120 million. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. In 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA. In March 2018, the EPA published the first phase of the proposed rule revisions in the Federal Register. In 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk-based management options at facilities based on site characteristics. In 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision resulted in a change to the status of three existing clay-lined impoundments at Boswell that must now be considered unlined. The EPA proposed additional rule revisions in 2019 to address outstanding issues from litigation and closure timelines for unlined impoundments, respectively. The first of these rules, CCR Part A Rule, was finalized in September 2020. The Part A Rule revision requires unlined impoundments to cease disposal of waste as soon as technically feasible but no later than April 11, 2021. This deadline has continued to toll as the EPA did not make any variance application determinations by that date. Minnesota Power sought EPA approval to extend the closure date for the two active Boswell impoundments in November 2020 through a variance application, and continues to operate the impoundments pending a final determination by the EPA. On January 11, 2022, the EPA issued a number of Part A and Part B variance application completeness determinations. The Boswell application was deemed complete; an approval or denial of the application is expected in mid-2022.

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NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Additionally, the EPA released a proposed Part B rulemaking in 2020 that addressed options for beneficial reuse of CCR materials, alternative liner demonstrations, and other CCR regulatory revisions. Portions of the Part B Rule addressing alternative liner equivalency standards were finalized in November 2020. According to the EPA’s regulatory agenda, finalization of the remainder of the proposed Part B Rule is expected in late 2022. Expected compliance costs at Boswell due to the court decision and subsequent rule revisions are reflected in our estimate of compliance costs for the CCR rule noted previously. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Other Environmental Matters

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. As of December 31, 2021, we have recorded a liability of approximately $18 million for remediation costs at this site after further refining the scope of work and cost estimates as well as incorporating detailed design components specific to the site in 2021 (approximately $7 million as of December 31, 2020); however, SWL&P continues to work with the WDNR on the extent of contamination which may result in additional remediation costs being identified. SWL&P has also recorded an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. Remediation costs are expected to be incurred through 2023.

Other Matters

We have multiple credit facility agreements in place that provide the ability to issue standby letters of credit to satisfy our contractual security requirements across our businesses. As of December 31, 2021, we had $134.7 million of outstanding letters of credit issued, including those issued under our revolving credit facility.

Regulated Operations. As of December 31, 2021, we had $10.9 million outstanding in standby letters of credit at our Regulated Operations which are pledged as security for MISO and state agency agreements as well as energy facilities under development.

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their output and expire in various years between 2022 and 2039. As of December 31, 2021, ALLETE Clean Energy has $87.4 million outstanding in standby letters of credit, the majority of which are pledged as security under these PSAs and PSAs for wind energy facilities under development.

Corporate and Other.

BNI Energy. As of December 31, 2021, BNI Energy had surety bonds outstanding of $71.2 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. BNI Energy’s total reclamation liability is currently estimated at $70.7 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds will be drawn upon.

Investment in Nobles 2. Nobles 2 wind energy facility requires standby letters of credit as security for certain contractual obligations. As of December 31, 2021, ALLETE South Wind has $12.5 million outstanding in standby letters of credit, related to our portion of the security requirements relative to our ownership in Nobles 2.

South Shore Energy. As of December 31, 2021, South Shore Energy had $23.9 million outstanding in standby letters of credit pledged as security in connection with the development of NTEC. South Shore Energy does not believe it is likely that any of these outstanding letters of credit will be drawn upon.

ALLETE Properties. As of December 31, 2021, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $2.0 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $1.0 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

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NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued

Community Development District Obligations. In 2005, the Town Center District issued $26.4 million of tax-exempt, 6.0 percent capital improvement revenue bonds. The capital improvement revenue bonds are payable over 31 years (by May 1, 2036) and are secured by special assessments on the benefited land. To the extent that ALLETE Properties still owns land at the time of the assessment, it will incur the cost of its portion of these assessments, based upon its ownership of benefited property.

As of December 31, 2021, we owned 30 percent of the assessable land in the Town Center District (48 percent as of December 31, 2020). As of December 31, 2021, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $1.8 million. As we sell property at this project, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

Minnesota Power has been named in a lawsuit where a contractor performing work at one of its facilities experienced an injury and subsequently filed a lawsuit seeking compensatory damages. Litigation related to this injury is ongoing. At this time, a loss is considered reasonably possible; however, we do not deem it probable, and we are unable to estimate a loss or range of loss related to the litigation at this time.

NOTE 9. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2018	51,509	$1,428.5
Employee Stock Purchase Plan	8	0.7
Invest Direct	38	3.0
Options and Stock Awards	85	1.3
Contributions to RSOP	39	3.2
Balance as of December 31, 2019	51,679	1,436.7
Employee Stock Purchase Plan	13	0.7
Invest Direct	309	18.3
Options and Stock Awards	35	2.2
Contributions to RSOP	49	3.0
Balance as of December 31, 2020	52,085	1,460.9
Employee Stock Purchase Plan	17	0.8
Invest Direct	263	17.5
Options and Stock Awards	49	3.4
Contributions to RSOP	24	3.1
Equity Issuance Program	782	51.0
Balance as of December 31, 2021	53,220	$1,536.7

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NOTE 9. COMMON STOCK AND EARNINGS PER SHARE (Continued)

Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, in 2008, as amended most recently in 2020, with respect to the issuance and sale of up to an aggregate of 13.6 million shares of our common stock, without par value, of which 2.1 million shares remain available for issuance as of December 31, 2021. For the year ended December 31, 2021, 0.8 million shares of common stock were issued under this agreement (none in 2020 and 2019) resulting in proceeds of $51.0 million.

Earnings Per Share. We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan.

Reconciliation of Basic and Diluted
Earnings Per Share		Dilutive
Year Ended December 31	Basic	Securities	Diluted
Millions Except Per Share Amounts
2021
Net Income Attributable to ALLETE	$169.2		$169.2
Average Common Shares	52.4	0.1	52.5
Earnings Per Share	$3.23		$3.23
2020
Net Income Attributable to ALLETE	$174.2		$174.2
Average Common Shares	51.9	—	51.9
Earnings Per Share	$3.36		$3.35
2019
Net Income Attributable to ALLETE	$185.6		$185.6
Average Common Shares	51.6	0.1	51.7
Earnings Per Share	$3.59		$3.59

NOTE 10. INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31	2021	2020	2019
Millions
Current Income Tax Expense (a)
Federal	—	—	—
State	—	—	$0.1
Total Current Income Tax Expense	—	—	$0.1
Deferred Income Tax Expense (Benefit)
Federal (b)	$(37.2)	$(48.8)	$(27.8)
State	10.8	9.8	21.7
Investment Tax Credit Amortization	(0.5)	(0.5)	(0.6)
Total Deferred Income Tax Expense (Benefit)	$(26.9)	$(39.5)	$(6.7)
Total Income Tax Expense (Benefit)	$(26.9)	$(39.5)	$(6.6)

(a)For the years ended December 31, 2021, 2020 and 2019, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation and related tax attributes from large wind projects. Federal and state NOLs are being carried forward to offset current and future taxable income.

(b)For the years ended December 31, 2021, 2020 and 2019, the federal tax benefit is primarily due to production tax credits.

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NOTE 10. INCOME TAX EXPENSE (Continued)

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2021		2020		2019
Millions
Income Before Non-Controlling Interest and Income Taxes	$110.9		$122.1		$178.9
Statutory Federal Income Tax Rate	21	%	21	%	21	%
Income Taxes Computed at Statutory Federal Rate	$23.3		$25.6		$37.6
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	8.6		7.7		17.2
Production Tax Credits	(53.5)		(62.7)		(50.7)
Regulatory Differences – Excess Deferred Tax Benefit (a)	(9.5)		(9.9)		(8.8)
U.S. Water Services Sale of Stock Basis Difference	—		—		1.7
Non-Controlling Interest	6.3		2.7		—
Share-Based Compensation	0.5		—		—
Other	(2.6)		(2.9)		(3.6)
Total Income Tax Expense (Benefit)	$(26.9)		$(39.5)		$(6.6)

(a)Excess deferred income taxes are being returned to customers under both the Average Rate Assumption Method and amortization periods as approved by regulators. (See Note 4. Regulatory Matters.)

The effective tax rate was a benefit of 24.3 percent for 2021 (benefit of 32.4 percent for 2020; benefit of 3.7 percent for 2019). The 2021 effective tax rate was primarily impacted by production tax credits and non-controlling interests in subsidiaries. The 2020 effective tax rate was primarily impacted by production tax credits. The 2019 effective tax rate was primarily impacted by production tax credits and the gain on sale of U.S. Water Services.

Deferred Income Tax Assets and Liabilities
As of December 31	2021	2020
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation	$44.5	$67.6
Property-Related	54.8	61.4
NOL Carryforwards	67.5	60.7
Tax Credit Carryforwards	509.1	455.7
Power Sales Agreements	16.5	20.1
Regulatory Liabilities	101.5	107.7
Other	—	22.4
Gross Deferred Income Tax Assets	793.9	795.6
Deferred Income Tax Asset Valuation Allowance	(69.0)	(69.9)
Total Deferred Income Tax Assets	$724.9	$725.7
Deferred Income Tax Liabilities
Property-Related	$680.8	$691.5
Regulatory Asset for Benefit Obligations	54.9	71.5
Unamortized Investment Tax Credits	30.5	31.1
Partnership Basis Differences	106.3	86.7
Regulatory Assets	30.0	32.6
Other	8.1	8.0
Total Deferred Income Tax Liabilities	$910.6	$921.4
Net Deferred Income Taxes (a)	$185.7	$195.7

(a)Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet.

ALLETE, Inc. 2021 Form 10-K

106

NOTE 10. INCOME TAX EXPENSE (Continued)

NOL and Tax Credit Carryforwards
As of December 31	2021	2020
Millions
Federal NOL Carryforwards (a)	$177.3	$197.5
Federal Tax Credit Carryforwards	$416.4	$362.9
State NOL Carryforwards (a)	$506.9	$270.1
State Tax Credit Carryforwards (b)	$24.2	$23.4

(a)Pre-tax amounts.

(b)Net of a $68.6 million valuation allowance as of December 31, 2021 ($69.4 million as of December 31, 2020).

The federal NOL and tax credit carryforward periods expire between 2030 and 2042. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore, no federal valuation allowance has been recognized as of December 31, 2021. The state NOL and tax credit carryforward periods expire between 2022 and 2045. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.

Gross Unrecognized Income Tax Benefits	2021	2020	2019
Millions
Balance at January 1	$1.4	$1.4	$1.6
Additions for Tax Positions Related to the Current Year	—	0.1	0.1
Additions for Tax Positions Related to Prior Years	—	—	0.1
Reductions for Tax Positions Related to Prior Years	(0.1)	(0.1)	(0.4)
Lapse of Statute	—	—	—
Balance as of December 31	$1.3	$1.4	$1.4

Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The gross unrecognized tax benefits as of December 31, 2021, included $0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2021, we had no accrued interest (none as of December 31, 2020, and 2019) related to unrecognized tax benefits included on the Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income. Interest expense related to unrecognized tax benefits on the Consolidated Statement of Income was immaterial in 2021, 2020 and 2019. There were no penalties recognized in 2021, 2020 or 2019. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

No material changes to unrecognized tax benefits are expected during the next 12 months.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has no open federal or state audits, and is no longer subject to federal examination for years before 2018 or state examination for years before 2017.

ALLETE, Inc. 2021 Form 10-K

107

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union, non-union and combined retiree defined benefit pension plans covering eligible employees. The combined retiree defined benefit pension plan was created in 2016, to include all union and non-union retirees from the existing plans as of January 1, 2016. The plans provide defined benefits based on years of service and final average pay. We contributed $10.3 million in cash to the plans in 2021 ($10.7 million in 2020; $10.4 million in 2019). We also have a defined contribution RSOP covering substantially all employees. The 2021 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $11.5 million ($11.2 million for the 2020 plan year; $10.8 million for the 2019 plan year). (See Note 9. Common Stock and Earnings Per Share and Note 12. Employee Stock and Incentive Plans.)

The non-union defined benefit pension plan was frozen in 2018, and does not allow further crediting of service or earnings to the plan. Further, it is closed to new participants. The Minnesota Power union defined benefit pension plan is also closed to new participants, and the SWL&P union defined benefit pension plan was closed to new participants effective February 1, 2022.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, the postretirement health care plan was closed to employees hired after January 31, 2011, and the eligibility requirements were amended. In 2014, the postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015, and in 2018, the postretirement life plan was amended to limit the benefit level for union employees retiring after December 31, 2018. The postretirement health and life plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In 2021, no contributions were made to the VEBAs (none in 2020; none in 2019) and no contributions were made to the grantor trusts (none in 2020; none in 2019).

Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the pension plans. Contributions are based on estimates and assumptions which are subject to change. We do not expect to make any contributions to the defined benefit pension plans in 2022, and we do not expect to make any contributions to the defined benefit postretirement health and life plans in 2022.

Accounting for defined benefit pension and other postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset (regulatory liability) on the Consolidated Balance Sheet, in accordance with the accounting standards for the effect of certain types of regulation applicable to our Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other operations are recognized in accumulated other comprehensive income.

ALLETE, Inc. 2021 Form 10-K

108

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
As of December 31	2021	2020
Millions
Accumulated Benefit Obligation	$875.5	$931.2
Change in Benefit Obligation
Obligation, Beginning of Year	$965.7	$854.0
Service Cost	11.0	10.7
Interest Cost	24.6	27.9
Plan Curtailments	(1.4)	—
Actuarial (Gain) Loss (a)	(39.0)	118.7
Benefits Paid	(56.5)	(54.4)
Participant Contributions	7.3	8.8
Obligation, End of Year	$911.7	$965.7
Change in Plan Assets
Fair Value, Beginning of Year	$759.4	$699.6
Actual Return on Plan Assets	23.1	93.0
Employer Contribution (b)	19.7	21.2
Benefits Paid	(56.5)	(54.4)
Fair Value, End of Year	$745.7	$759.4
Funded Status, End of Year	$(166.0)	$(206.3)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(2.1)	$(2.2)
Non-Current Liabilities	$(163.9)	$(204.1)

(a)    Actuarial (gain) loss was primarily the result of increases in discount rates in 2021 compared to decreases in 2020.

(b)    Includes Participant Contributions noted above.

The pension costs that are reported as a component within the Consolidated Balance Sheet, reflected in long-term regulatory assets or liabilities and accumulated other comprehensive income, consist of a net loss of $260.2 million and prior service credit of $1.0 million as of December 31, 2021 (net loss of $299.0 million and prior service credit of $1.1 million as of December 31, 2020).

ALLETE, Inc. 2021 Form 10-K

109

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2021	2020
Millions
Net Loss	$(260.2)	$(299.0)
Prior Service Credit	1.0	1.1
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	93.2	91.6
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(166.0)	$(206.3)

Components of Net Periodic Pension Cost
Year Ended December 31	2021	2020	2019
Millions
Service Cost	$11.0	$10.7	$9.3
Non-Service Cost Components (a)
Interest Cost	24.6	27.9	31.9
Expected Return on Plan Assets	(43.4)	(42.7)	(44.2)
Amortization of Loss	18.8	12.8	7.5
Amortization of Prior Service Credit	(0.2)	(0.2)	(0.1)
Net Pension Cost	$10.8	$8.5	$4.4

(a)These components of net periodic pension cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2021	2020
Millions
Net (Gain) Loss	$(20.1)	$68.4
Amortization of Prior Service Credit	0.2	0.2
Amortization of Loss	(18.8)	(12.8)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(38.7)	$55.8

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2021	2020
Millions
Projected Benefit Obligation	$911.7	$965.7
Accumulated Benefit Obligation	$875.5	$931.2
Fair Value of Plan Assets	$745.7	$759.4

ALLETE, Inc. 2021 Form 10-K

110

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Postretirement Health and Life Obligation and Funded Status
As of December 31	2021	2020
Millions
Change in Benefit Obligation
Obligation, Beginning of Year	$167.6	$149.8
Service Cost	3.6	3.3
Interest Cost	4.4	5.0
Actuarial (Gain) Loss (a)	(19.7)	19.2
Benefits Paid	(10.6)	(12.6)
Participant Contributions	2.9	3.2
Plan Curtailments	—	(0.3)
Obligation, End of Year	$148.2	$167.6
Change in Plan Assets
Fair Value, Beginning of Year	$186.0	$173.7
Actual Return on Plan Assets	22.8	20.9
Employer Contribution	0.7	0.8
Participant Contributions	2.9	3.2
Benefits Paid	(10.6)	(12.6)
Fair Value, End of Year	$201.8	$186.0
Funded Status, End of Year	$53.6	$18.4
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$64.8	$34.2
Current Liabilities	$(1.4)	$(0.6)
Non-Current Liabilities	$(9.8)	$(15.2)

(a)Actuarial (gain) loss was primarily the result of increases in discount rates in 2021 compared to decreases in 2020.

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $13.2 million in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of December 31, 2021 ($20.4 million as of December 31, 2020).

The postretirement health and life costs that are reported as a component within the Consolidated Balance Sheet, reflected in regulatory long-term assets or liabilities and accumulated other comprehensive income, consist of the following:

Unrecognized Postretirement Health and Life Costs
As of December 31	2021	2020
Millions
Net (Gain) Loss	$(12.7)	$23.0
Prior Service Credit	(20.7)	(28.3)
Total Unrecognized Postretirement Health and Life Cost	$(33.4)	$(5.3)

ALLETE, Inc. 2021 Form 10-K

111

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2021	2020
Millions
Net Gain (Loss) (a)	$12.7	$(23.0)
Prior Service Credit	20.7	28.3
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	20.2	13.1
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$53.6	$18.4

(a)Excludes gains, losses and contributions associated with irrevocable grantor trusts.

Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2021	2020	2019
Millions
Service Cost	$3.6	$3.3	$3.9
Non-Service Cost Components (a)
Interest Cost	4.4	5.0	7.3
Expected Return on Plan Assets	(9.9)	(9.7)	(10.5)
Amortization of Loss	3.0	1.0	0.5
Amortization of Prior Service Credit	(7.6)	(8.0)	(2.8)
Effect of Plan Curtailment	—	(0.3)	(2.1)
Net Postretirement Health and Life Credit	$(6.5)	$(8.7)	$(3.7)

(a)These components of net periodic postretirement health and life cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2021	2020
Millions
Net (Gain) Loss	$(32.7)	$8.1
Amortization of Prior Service Credit	7.6	8.0
Amortization of Loss	(3.0)	(1.0)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(28.1)	$15.1

Estimated Future Benefit Payments	Pension	Postretirement Health and Life
Millions
2022	$54.6	$8.4
2023	$54.4	$8.4
2024	$54.4	$8.4
2025	$53.8	$8.2
2026	$53.1	$8.1
Years 2027 – 2031	$257.2	$41.6

ALLETE, Inc. 2021 Form 10-K

112

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Weighted Average Assumptions Used to Determine Benefit Obligation
As of December 31	2021	2020
Discount Rate
Pension	3.05%	2.62%
Postretirement Health and Life	3.09%	2.70%
Rate of Compensation Increase	3.58%	3.61%
Health Care Trend Rates
Trend Rate	5.66%	5.81%
Ultimate Trend Rate	4.50%	4.50%
Year Ultimate Trend Rate Effective	2038	2038

Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2021	2020	2019
Discount Rate
Pension	2.87%	3.52%	4.67%
Postretirement Health and Life	2.70%	3.45%	4.47%
Expected Long-Term Return on Plan Assets (a)
Pension	6.50%	6.75%	7.25%
Postretirement Health and Life	5.85%	6.08%	6.51%
Rate of Compensation Increase	3.62%	4.06%	4.04%

(a)The expected long-term rates of return used to determine net periodic benefit expense for 2022 have been reduced to 6.00 percent for pension expense and 4.80 percent to 6.00 percent for postretirement health and life expense.

In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.

The discount rate is computed using a bond matching study which utilizes a portfolio of high quality bonds that produce cash flows similar to the projected costs of our pension and other postretirement plans.

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2021, considered a modified PRI-2012 mortality table and MP-2021 mortality projection scale.

ALLETE, Inc. 2021 Form 10-K

113

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Actual Plan Asset Allocations	Pension		Postretirement Health and Life (a)
	2021	2020	2021	2020
Equity Securities	49%	36%	70%	67%
Fixed Income Securities	48%	61%	29%	32%
Private Equity	—	1	1%	1%
Real Estate	3%	2%	—	—
	100%	100%	100%	100%

(a)Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities as of December 31, 2021 (no shares as of December 31, 2020).

The defined benefit pension plans have adopted a dynamic asset allocation strategy (glide path) that increases the invested allocation to fixed income assets as the funding level of the plan increases to better match the sensitivity of the plan’s assets and liabilities to changes in interest rates. This is expected to reduce the volatility of reported pension plan expenses. The postretirement health and life plans’ assets are diversified to achieve strong returns within managed risk. Equity securities are diversified among domestic companies with large, mid and small market capitalizations, as well as investments in international companies. The majority of debt securities are made up of investment grade bonds.

Following are the current targeted allocations as of December 31, 2021:

Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	49	%	60	%
Fixed Income Securities	49	%	37	%
Private Equity	1	%	—
Real Estate	1	%	3	%
	100	%	100	%

(a)Includes VEBAs and irrevocable grantor trusts.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). (See Note 6. Fair Value.)

ALLETE, Inc. 2021 Form 10-K

114

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Pension Fair Value

	Fair Value as of December 31, 2021
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—	$113.8	—	$113.8
U.S. Mid-cap Growth (a)	—	47.6	—	47.6
U.S. Small-cap (a)	—	46.2	—	46.2
International	—	158.2	—	158.2
Fixed Income Securities (a)	—	346.1	—	346.1
Cash and Cash Equivalents	$12.2	—	—	12.2
Private Equity Funds	—	—	—	—
Real Estate	—	—	$21.6	21.6
Total Fair Value of Assets	$12.2	$711.9	$21.6	$745.7

(a)The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity and fixed income securities indexes.

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds	Real Estate
Millions
Balance as of December 31, 2020	$7.0	$18.0
Actual Return on Plan Assets	(3.5)	3.6
Purchases, Sales, and Settlements – Net	(3.5)	—
Balance as of December 31, 2021	—	$21.6

	Fair Value as of December 31, 2020
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—	$91.7	—	$91.7
U.S. Mid-cap Growth (a)	—	40.0	—	40.0
U.S. Small-cap (a)	—	40.7	—	40.7
International	—	97.1	—	97.1
Fixed Income Securities (a)	—	461.7	—	461.7
Cash and Cash Equivalents	$3.2	—	—	3.2
Private Equity Funds	—	—	$7.0	7.0
Real Estate	—	—	18.0	18.0
Total Fair Value of Assets	$3.2	$731.2	$25.0	$759.4

(a)The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity and fixed income securities indexes.

ALLETE, Inc. 2021 Form 10-K

115

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds	Real Estate
Millions
Balance as of December 31, 2019	$8.0	$18.0
Actual Return on Plan Assets	0.1	—
Purchases, Sales, and Settlements – Net	(1.1)	—
Balance as of December 31, 2020	$7.0	$18.0

Postretirement Health and Life Fair Value

	Fair Value as of December 31, 2021
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap	$40.1	—	—	$40.1
U.S. Mid-cap Growth	37.3	—	—	37.3
U.S. Small-cap	19.3	—	—	19.3
International	43.7	—	—	43.7
Fixed Income Securities:
Mutual Funds	56.7	—	—	56.7
Debt Securities	—	$1.8	—	1.8
Cash and Cash Equivalents	0.9	—	—	0.9
Private Equity Funds	—	—	$2.0	2.0
Total Fair Value of Assets	$198.0	$1.8	$2.0	$201.8

(a)The underlying investments consist of mutual funds (Level 1). 

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2020	$1.7
Actual Return on Plan Assets	0.8
Purchases, Sales, and Settlements – Net	(0.5)
Balance as of December 31, 2021	$2.0

ALLETE, Inc. 2021 Form 10-K

116

NOTE 11. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

	Fair Value as of December 31, 2020
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap	$34.2	—	—	$34.2
U.S. Mid-cap Growth	31.4	—	—	31.4
U.S. Small-cap	16.6	—	—	16.6
International	41.5	—	—	41.5
Fixed Income Securities:
Mutual Funds	57.3	—	—	57.3
Debt Securities	—	$2.2	—	2.2
Cash and Cash Equivalents	1.1	—	—	1.1
Private Equity Funds	—	—	$1.7	1.7
Total Fair Value of Assets	$182.1	$2.2	$1.7	$186.0

(a)The underlying investments consist of mutual funds (Level 1). 

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2019	$1.7
Actual Return on Plan Assets	—
Purchases, Sales, and Settlements – Net	—
Balance as of December 31, 2020	$1.7

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.

NOTE 12. EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor an ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire. The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings. ESOP employer allocations are funded with contributions paid in either cash or the issuance of ALLETE common stock at the Company’s discretion. We record compensation expense equal to the cash or current market price of stock contributed. ESOP compensation expense was $11.5 million in 2021 ($11.2 million in 2020; $10.8 million in 2019).

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock held and purchased by the ESOP were treated as unearned ESOP shares and not considered outstanding for earnings per share computations. All ESOP shares have been allocated to participants as of December 31, 2021, 2020 and 2019.

Stock-Based Compensation.

Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, restricted stock units, stock appreciation rights and other awards. There are 0.7 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.7 million of these shares remain available for issuance as of December 31, 2021.

ALLETE, Inc. 2021 Form 10-K

117

NOTE 12. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

The following types of share-based awards were outstanding in 2021, 2020 or 2019:

Performance Shares. Under the performance share awards, the number of shares earned is contingent upon attaining specific market and performance goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies while performance goals are measured by earnings per share growth. In the case of qualified retirement, death, or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death, or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards incorporates the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

Restricted Stock Units. Under the restricted stock unit awards, shares for participants eligible for retirement vest monthly over a three-year period. For participants not eligible for retirement, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.

Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price; we are not required to apply fair value accounting to these awards as the discount is not greater than 5 percent.

RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.

The following share-based compensation expense amounts were recognized in our Consolidated Statement of Income for the periods presented.

Share-Based Compensation Expense
Year Ended December 31	2021	2020	2019
Millions
Performance Shares	$2.0	$2.2	$2.3
Restricted Stock Units	1.0	0.9	0.8
Total Share-Based Compensation Expense	$3.0	$3.1	$3.1
Income Tax Benefit	$0.9	$0.9	$0.9

There were no capitalized share-based compensation costs during the years ended December 31, 2021, 2020 or 2019.

As of December 31, 2021, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $1.8 million and $0.9 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years and 1.6 years, respectively.

ALLETE, Inc. 2021 Form 10-K

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NOTE 12. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

Performance Shares. The following table presents information regarding our non-vested performance shares.

	2021		2020		2019
	Number of Shares	Weighted- Average Grant Date Fair Value	Number of Shares	Weighted- Average Grant Date Fair Value	Number of Shares	Weighted- Average Grant Date Fair Value
Non-vested as of January 1	85,284	$80.73	99,585	$72.78	129,693	$66.12
Granted (a)	33,304	$73.25	25,763	$83.17	60,747	$63.89
Awarded	—	—	(25,304)	$62.03	(75,943)	$53.44
Unearned Grant Award	(33,375)	$86.09	(13,625)	$62.03	—	—
Forfeited	(4,552)	$74.05	(1,135)	$79.81	(14,912)	$77.14
Non-vested as of December 31	80,661	$75.80	85,284	$80.73	99,585	$72.78

(a)    Shares granted include accrued dividends.

There were approximately 32,000 performance shares granted in February 2022 for the three-year performance period ending in 2024. The ultimate issuance is contingent upon the attainment of certain goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was $2.2 million. There were no performance shares awarded in February 2022.

Restricted Stock Units. The following table presents information regarding our available restricted stock units.

	2021		2020		2019
	Number of Shares	Weighted- Average Grant Date Fair Value	Number of Shares	Weighted- Average Grant Date Fair Value	Number of Shares	Weighted- Average Grant Date Fair Value
Available as of January 1	37,482	$77.64	39,943	$69.30	49,771	$60.74
Granted (a)	16,251	$64.97	15,169	$83.48	13,927	$74.93
Awarded	(23,631)	$74.53	(17,193)	$63.41	(21,110)	$52.44
Forfeited	(1,961)	$74.52	(437)	$77.52	(2,645)	$72.43
Available as of December 31	28,141	$73.16	37,482	$77.64	39,943	$69.30

(a)    Shares granted include accrued dividends.

There were approximately 13,000 restricted stock units granted in February 2022 for the vesting period ending in 2024. The grant date fair value of the restricted stock units granted was $0.8 million. There were approximately 7,000 restricted stock units awarded in February 2022. The grant date fair value of the shares awarded was $0.5 million.

NOTE 13. BUSINESS SEGMENTS

We present three reportable segments: Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes three operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services was our integrated water management company, which reflects operating results until it was sold in March 2019. We also present Corporate and Other which includes two operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with our investment in Nobles 2, South Shore Energy, our non-rate regulated, Wisconsin subsidiary developing NTEC, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE, Inc. 2021 Form 10-K

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NOTE 13. BUSINESS SEGMENTS (Continued)

Year Ended December 31	2021	2020	2019
Millions
Operating Revenue
Residential	$160.8	$140.7	$139.6
Commercial	168.6	139.5	145.7
Municipal	52.0	41.2	48.6
Industrial	565.5	432.8	476.4
Other Power Suppliers	168.7	138.8	153.7
CIP Financial Incentive (a)	2.4	2.4	2.8
Other	109.9	91.9	75.6
Total Regulated Operations	1,227.9	987.3	1,042.4
ALLETE Clean Energy
Long-term PSA	75.5	68.3	48.0
Other	11.4	11.3	11.6
Total ALLETE Clean Energy	86.9	79.6	59.6
U.S. Water Services (b)
Point-in-time	—	—	19.0
Contract	—	—	9.2
Capital Project	—	—	5.2
Total U.S. Water Services	—	—	33.4
Corporate and Other
Long-term Contract	84.4	86.0	82.8
Other	20.0	16.2	22.3
Total Corporate and Other	104.4	102.2	105.1
Total Operating Revenue	$1,419.2	$1,169.1	$1,240.5
Net Income (Loss) Attributable to ALLETE (c)
Regulated Operations	$129.1	$136.3	$154.4
ALLETE Clean Energy	26.3	29.9	12.4
U.S. Water Services	—	—	(1.1)
Corporate and Other (b)(d)	13.8	8.0	19.9
Total Net Income Attributable to ALLETE	$169.2	$174.2	$185.6

(a)    See Note 4. Regulatory Matters.

(b)     In 2019, ALLETE sold U.S. Water Services. The Company recognized a gain on the sale of $13.2 million after-tax which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)

(c)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. 

(d)    In 2021, South Shore Energy sold a portion of its undivided ownership interest in NTEC to Basin. The closing of the transaction resulted in the recognition of an approximately $8.5 million after-tax gain which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)

ALLETE, Inc. 2021 Form 10-K

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NOTE 13. BUSINESS SEGMENTS (Continued)

Year Ended December 31	2021	2020	2019
Millions
Depreciation and Amortization
Regulated Operations	$170.7	$166.9	$159.4
ALLETE Clean Energy	49.2	37.9	26.8
U.S. Water Services	—	—	2.3
Corporate and Other	11.8	13.0	13.5
Total Depreciation and Amortization	$231.7	$217.8	$202.0
Interest Expense (a)
Regulated Operations	$57.3	$58.5	$58.9
ALLETE Clean Energy	1.5	2.2	2.8
U.S. Water Services	—	—	0.2
Corporate and Other	13.2	13.2	8.0
Eliminations	(2.9)	(8.3)	(5.0)
Total Interest Expense	$69.1	$65.6	$64.9
Equity Earnings
Regulated Operations	$21.3	$22.3	$21.7
Corporate and Other	(1.3)	(0.2)	—
Total Equity Earnings	$20.0	$22.1	$21.7
Income Tax Expense (Benefit)
Regulated Operations	$(16.6)	$(19.4)	$(7.1)
ALLETE Clean Energy	(16.6)	(19.1)	(11.9)
U.S. Water Services	—	—	(0.4)
Corporate and Other (b)	6.3	(1.0)	12.8
Total Income Tax Benefit	$(26.9)	$(39.5)	$(6.6)

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.    

(b) In 2019, ALLETE sold U.S. Water Services. The Company recognized income tax expense of $10.4 million for the gain on sale of U.S. Water Services which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)

As of December 31	2021	2020
Millions
Assets
Regulated Operations	$4,289.4	$4,196.8
ALLETE Clean Energy	1,719.4	1,483.3
Corporate and Other	426.2	404.5
Total Assets	$6,435.0	$6,084.6
Capital Expenditures
Regulated Operations	$166.8	$133.7
ALLETE Clean Energy	269.9	507.8
Corporate and Other	39.7	15.7
Total Capital Expenditures	$476.4	$657.2

ALLETE, Inc. 2021 Form 10-K

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NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED)

Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.

Quarter Ended	Mar. 31	Jun. 30	Sept. 30	Dec. 31
Millions Except Earnings Per Share
2021
Operating Revenue	$339.2	$335.6	$345.4	$399.0
Operating Income	$42.0	$28.2	$31.1	$50.0
Net Income Attributable to ALLETE	$51.8	$27.9	$27.6	$61.9
Earnings Per Share of Common Stock
Basic	$0.99	$0.53	$0.53	$1.18
Diluted	$0.99	$0.53	$0.53	$1.18
2020
Operating Revenue	$311.6	$243.2	$293.9	$320.4
Operating Income	$60.2	$12.7	$41.6	$36.4
Net Income Attributable to ALLETE	$66.3	$20.1	$40.7	$47.1
Earnings Per Share of Common Stock
Basic	$1.28	$0.39	$0.78	$0.91
Diluted	$1.28	$0.39	$0.78	$0.90
2019
Operating Revenue	$357.2	$290.4	$288.3	$304.6
Operating Income	$56.8	$36.2	$37.0	$49.8
Net Income Attributable to ALLETE	$70.5	$34.2	$31.2	$49.7
Earnings Per Share of Common Stock
Basic	$1.37	$0.66	$0.60	$0.96
Diluted	$1.37	$0.66	$0.60	$0.96

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves

	Balance at Beginning of Period	Additions		Deductions from Reserves (a)	Balance at End of Period
		Charged to Income	Other Charges
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2019 Trade Accounts Receivable	$1.7	$(0.1)	—	$0.7	$0.9
Finance Receivables – Long-Term	—	—	—	—	—
2020 Trade Accounts Receivable	$0.9	$2.7	—	$1.1	$2.5
Finance Receivables – Long-Term	—	—	—	—	—
2021 Trade Accounts Receivable	$2.5	$1.2	—	$1.9	$1.8
Finance Receivables – Long-Term	—	—	—	—	—
Deferred Asset Valuation Allowance
2019 Deferred Tax Assets	$66.5	$3.5	—	—	$70.0
2020 Deferred Tax Assets	$70.0	$(0.1)	—	—	$69.9
2021 Deferred Tax Assets	$69.9	$(0.9)	—	—	$69.0

(a)    Includes uncollectible accounts written-off.

ALLETE, Inc. 2021 Form 10-K

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