10-K

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, 2022

☐	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, 2022, was $3,349,606,300.

As of February 1, 2023, there were 57,252,864 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 2023 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	18
	Franchises	18
	ALLETE Clean Energy	18
	Corporate and Other	19
	New Energy	19
	Investment in Nobles 2	20
	South Shore Energy	20
	BNI Energy	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
	2022 Compared to 2021	38
	Critical Accounting Policies	42
	Outlook	44
	Liquidity and Capital Resources	52
	Capital Requirements	55
	Environmental and Other Matters	55
	Market Risk	55
	Recently Adopted Accounting Standards	56
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk	56
	Item 8. Financial Statements and Supplementary Data	57

ALLETE, Inc. 2022 Form 10-K

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Index (Continued)

	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	57
	Item 9A. Controls and Procedures	57
	Item 9B. Other Information	57
	Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	57
Part III		58
	Item 10. Directors, Executive Officers and Corporate Governance	58
	Item 11. Executive Compensation	58
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
	Item 13. Certain Relationships and Related Transactions, and Director Independence	59
	Item 14. Principal Accountant Fees and Services	59
Part IV		60
	Item 15. Exhibits and Financial Statement Schedules	60
	Item 16. Form 10-K Summary	64
Signatures		65
Report of Independent Registered Public Accounting Firm		67
Consolidated Financial Statements - Audited		69
	Consolidated Balance Sheet	69
	Consolidated Statement of Income	70
	Consolidated Statement of Comprehensive Income	71
	Consolidated Statement of Cash Flows	72
	Consolidated Statement of Equity	73
	Notes to Consolidated Financial Statements	74
	Note 1. Operations and Significant Accounting Policies	74
	Note 2. Property, Plant and Equipment	87
	Note 3. Jointly-Owned Facilities and Assets	88
	Note 4. Regulatory Matters	89
	Note 5. Acquisitions	93
	Note 6. Equity Investments	94
	Note 7. Fair Value	95
	Note 8. Short-Term and Long-Term Debt	97
	Note 9. Commitments, Guarantees and Contingencies	100
	Note 10. Common Stock and Earnings Per Share	108
	Note 11. Income Tax Expense	109
	Note 12. Pension and Other Postretirement Benefit Plans	112
	Note 13. Employee Stock and Incentive Plans	121
	Note 14. Business Segments	123
	Note 15. Quarterly Financial Data (Unaudited)	126
Schedule II		126

ALLETE, Inc. 2022 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
Cenovus Energy	Cenovus Energy Inc.
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.
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. 2022 Form 10-K

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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
New Energy	New Energy Equity LLC
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
ST Paper	ST Paper LLC
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
USS Corporation	United States Steel Corporation
WTG	Wind Turbine Generator

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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. 2022 Form 10-K

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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. In 2020, ALLETE’s largest business, Minnesota Power, reached a milestone of providing 50 percent renewable energy to its retail and municipal customers in Minnesota, and the Company 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 or 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.

Minnesota Power’s latest IRP, approved by the MPUC in an order dated January 9, 2023, 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 up to 700 MW of new wind and solar energy resources, and ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. 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.

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.

On February 7, 2023, the Minnesota Governor signed into law legislation that updates the state’s renewable energy standard and requires Minnesota electric utilities to source retail sales with 100 percent carbon-free energy by 2040. The Company is evaluating the law to identify challenges and opportunities it could present. (See Regulated Operations – Minnesota Legislation.)

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 investing in ALLETE Clean Energy and New 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.

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 14 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 1,200 MW of nameplate capacity wind energy generation with a majority contracted under PSAs of various durations. In addition, ALLETE Clean Energy engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion. ALLETE Clean Energy currently has approximately 100 MW of wind energy facilities under contract to be sold to others.

ALLETE, Inc. 2022 Form 10-K

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Overview (Continued)

Corporate and Other is comprised of New Energy, a renewable development company; 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; BNI Energy, our coal mining operations in North Dakota; 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; land holdings 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, 2022, 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	2022		2021		2020
Consolidated Operating Revenue – Millions (a)	$1,570.7		$1,419.2		$1,169.1
Percentage of Consolidated Operating Revenue
Regulated Operations	80	%	87	%	84	%
ALLETE Clean Energy	8	%	6	%	7	%
Corporate and Other (a)	12	%	7	%	9	%
	100	%	100	%	100	%

(a)    2022 includes revenue from New Energy, which was acquired in the second quarter of 2022. (See Note. 5 Acquisitions.)

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 14. Business Segments.

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REGULATED OPERATIONS

Electric Sales / Customers

Regulated Utility Kilowatt-hours Sold
Year Ended December 31	2022	%	2021	%	2020	%
Millions
Retail and Municipal
Residential	1,148	9	1,135	7	1,134	9
Commercial	1,359	11	1,359	9	1,306	10
Industrial	6,745	52	7,196	47	6,192	47
Municipal	540	4	590	4	584	4
Total Retail and Municipal	9,792	76	10,280	67	9,216	70
Other Power Suppliers	3,149	24	5,102	33	4,039	30
Total Regulated Utility Kilowatt-hours Sold	12,941	100	15,382	100	13,255	100

Industrial Customers. In 2022, industrial customers represented 52 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 COVID-19 pandemic and related governmental responses led to a 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. In 2022 Cliffs decided to idle all production at its Northshore mine until at least April 2023.

Industrial Customer Kilowatt-hours Sold
Year Ended December 31	2022	%	2021	%	2020	%
Millions
Taconite	4,713	70	5,281	73	4,296	69
Paper, Pulp and Secondary Wood Products	735	11	702	10	752	12
Pipelines and Other Industrial	1,297	19	1,213	17	1,144	19
Total Industrial Customer Kilowatt-hours Sold	6,745	100	7,196	100	6,192	100

Six taconite facilities served by Minnesota Power made up approximately 85 percent of 2021 iron ore pellet production in the U.S. according to data from the Minnesota Department of Revenue 2022 Mining Tax Guide. These taconite facilities are owned by Cliffs and USS Corporation. (See Large Power Customer Contracts.) Sales to taconite customers represented 4,713 million kWh, or 70 percent of total industrial customer kWh sales in 2022. 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.

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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 78 percent of capacity in 2022 (82 percent in 2021 and 68 percent in 2020). 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 2023 will increase by approximately 2 percent compared to 2022.

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

Minnesota Power Taconite Customer Production
Year	Tons (Millions)
2022*	32
2021	39
2020	30
2019	37
2018	39
2017	38
2016	28
2015	31
2014	39
2013	37
Source: Minnesota Department of Revenue 2022 Mining Tax Guide for years 2013 - 2021.
* 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 735 million kWh, or 11 percent of total industrial customer kWh sales in 2022. Minnesota Power also has an agreement to provide steam for one paper and pulp customer for use in the customer’s operations. The major paper and pulp mills we serve reported operating at similar levels in 2022 compared to 2021. 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 – ST Paper.)

Large Power Customer Contracts. Minnesota Power had seven Large Power Customer contracts as of December 31, 2022, each serving requirements of 10 MW or more of customer load. The customers as of December 31, 2022 consisted of six taconite facilities owned by Cliffs and USS Corporation as well as three 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, 2022

Customer	Industry	Location	Ownership	Earliest Termination Date
Cliffs – Minorca Mine (a)	Taconite	Virginia, MN	Cliffs	December 31, 2026
Hibbing Taconite (a)	Taconite	Hibbing, MN	85.3% Cliffs 14.7% USS Corporation	December 31, 2026
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, 2026
Boise, Inc. (a)	Paper	International Falls, MN	Packaging Corporation of America	December 31, 2026
UPM Blandin	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	December 31, 2029
Sappi Cloquet LLC (a)	Paper and Pulp	Cloquet, MN	Sappi Limited	December 31, 2026

(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, 2026.

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

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REGULATED OPERATIONS (Continued)

Residential and Commercial Customers. In 2022, residential and commercial customers represented 20 percent of total regulated utility kWh sales.

Municipal Customers. In 2022, municipal customers represented 4 percent of total regulated utility kWh sales.

Minnesota Power’s wholesale electric contracts with 14 non-affiliated municipal customers in Minnesota have termination dates ranging from 2029 through 2037, with a majority of contracts expiring in 2029. One of these wholesale contracts includes 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 9. Commitments, Guarantees and Contingencies, with additional disclosure provided in the following paragraphs.

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 32 percent to Minnkota Power in 2022 (28 percent in 2021 and in 2020). Minnkota Power’s net entitlement increases to approximately 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. Minnesota Power has a PSA with Silver Bay Power through 2031 to supply the full energy requirements for Silver Bay Power. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power.

Hibbing Public Utilities. In April 2022, Minnesota Power entered into a new long-term Power Purchase and Market Energy Service Agreement with Hibbing Public Utilities for the period of June 1, 2022, through May 31, 2027. The agreement replaced the previous wholesale electric contract between Hibbing Public Utilities and Minnesota 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, 2022, approximately 50 percent of Minnesota Power’s power supply for its retail and municipal customers in Minnesota 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 plans to cease coal operations at by 2030 and 2035, respectively. (See Regulatory Matters.) The following table reflects Minnesota Power’s generating capabilities as of December 31, 2022, and total electrical supply for 2022. Minnesota Power had an annual net peak load of 1,556 MW on January 7, 2022.

ALLETE, Inc. 2022 Form 10-K

12

REGULATED OPERATIONS (Continued)

Power Supply (Continued)

					Year Ended
	Unit	Year	Net		December 31, 2022
Regulated Utility Power Supply	No.	Installed	Capability		Generation and Purchases
			MW		MWh	%
Coal-Fired
Boswell Energy Center (a)	3	1973	352
in Cohasset, MN	4	1980	468	(b)
			820		4,520,828	33.9
Taconite Harbor Energy Center	1 & 2	1957	150	(c)	—	—
Total Coal-Fired			970		4,520,828	33.9
Biomass Co-Fired / Natural Gas
Hibbard Renewable Energy Center in Duluth, MN	3 & 4	1949, 1951	60		134,049	1.0
Laskin Energy Center in Hoyt Lakes, MN	1 & 2	1953	98		122,277	0.9
Total Biomass Co-Fired / Natural Gas			158		256,326	1.9
Hydro (d)
Group consisting of ten stations in MN	Multiple	Multiple	120		546,876	4.1
Wind (e)
Taconite Ridge Energy Center in Mtn. Iron, MN	Multiple	2008	25		62,168	0.5
Bison Wind Energy Center in Oliver and Morton Counties, ND	Multiple	2010-2014	497		1,566,952	11.8
Total Wind			522		1,629,120	12.3
Solar (f)
Group consisting of two solar arrays in MN	Multiple	Multiple	10		16,169	0.1
Total Generation			1,780		6,969,319	52.3
Long-Term Purchased Power
Lignite Coal - Square Butte near Center, ND (g)					1,192,480	8.9
Wind - Oliver Wind I and II in Oliver County, ND					407,253	3.0
Wind - Nobles 2 in Nobles County, MN (h)					1,091,676	8.2
Hydro - Manitoba Hydro in Manitoba, Canada					1,460,000	11.0
Total Long-Term Purchased Power					4,151,409	31.1
Other Purchased Power (i)					2,210,192	16.6
Total Purchased Power					6,361,601	47.7
Total Regulated Utility Power Supply					13,330,920	100.0

(a) Minnesota Power anticipates ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. (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 in the first quarter of 2023. (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. 2022 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 2022 for electric generation at Minnesota Power’s coal-fired generating stations was 2.7 million tons (2.7 million tons in 2021; 2.2 million tons in 2020). As of December 31, 2022, Minnesota Power had coal inventories of 0.8 million tons (0.4 million tons as of December 31, 2021). Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2023. In 2023, 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	2022	2021	2020
Average Price per Ton	$39.98	$39.51	$34.94
Average Price per MBtu	$2.25	$2.18	$1.93

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 9. 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 9. 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 2022 was approximately $2.05 per MBtu ($1.94 per MBtu in 2021; $1.75 per MBtu in 2020). (See Electric Sales / Customers – Minnkota Power PSA.)

Manitoba Hydro. Minnesota Power has two long-term PPAs with Manitoba Hydro. The first PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro through May 2035. The second PPA provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro through June 2040. A third PPA, which expired in April 2022 was an energy-only agreement, which primarily consisted of surplus hydro energy on Manitoba Hydro’s system that was delivered to Minnesota Power on a non-firm basis.

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 (8 miles), 115 kV (1,376 miles) and less than 115 kV (6,416 miles). We own and operate 162 substations with a total capacity of 10,116 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. 2022 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, 2022, our equity investment in ATC was $165.4 million ($154.5 million as of December 31, 2021). (See Note 6. 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 which is subject to various outstanding legal challenges related to the return on equity calculation and refund period ordered by the FERC. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the 2020 FERC order back to the FERC. As a result of this decision, ATC recorded a reserve in the third quarter of 2022 for anticipated refunds to its customers for approximately $31 million of which our share was approximately $2.4 million pre-tax. We cannot predict the return on equity the FERC will ultimately authorize in the remanded proceeding.

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 most recent 10-year transmission assessment, which covers the years 2022 through 2031, identifies a need for between $5.1 billion and $6.2 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 through 2021 were 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.

ALLETE, Inc. 2022 Form 10-K

15

REGULATED OPERATIONS (Continued)

Regulatory Matters (Continued)

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.

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 are now 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.

At a hearing on January 23, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. Upon commencement of final rates, we expect additional revenue from base rates of approximately $60 million and an additional $10 million in revenue recognized under cost recovery riders on an annualized basis, subject to final written order and reconsideration. Final rates are expected to commence in the third quarter of 2023; interim rates will be collected through this period with reserves recorded as necessary. As a result of the MPUC’s determinations made on January 23, 2023, Minnesota Power has recorded a reserve for an interim rate refund of approximately $18 million pre-tax as of December 31, 2022, which is subject to MPUC approval of Minnesota Power’s refund calculation. In addition, Minnesota Power recorded a charge of approximately $8 million pre-tax to write-off the deferred portion of residential customer interim rates. Minnesota Power also recorded additional revenue of approximately $9 million pre-tax for an increase in expected recoveries under its cost recovery riders.

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, which was approved by the MPUC in an order dated January 9, 2023. The approved IRP, which reflects a joint agreement reached with various stakeholders, outlines Minnesota Power’s 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 up to 700 MW of new wind and solar energy resources, and ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. 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. Minnesota Power is expected to file its next IRP by March 1, 2025.

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 achievement, in 2020, of now providing 50 percent renewable energy to its customers.

ALLETE, Inc. 2022 Form 10-K

16

REGULATED OPERATIONS (Continued)

Regulatory Matters (Continued)

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 retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.4 percent and a 55.0 percent equity ratio.

In 2022, SWL&P filed a rate increase request with the PSCW seeking an average increase of 3.6 percent for retail customers. The filing sought an overall return on equity of 10.4 percent and a 55 percent equity ratio. On an annualized basis, the requested final rate increase would have generated an estimated $4.3 million in additional revenue. In an order dated December 20, 2022, the PSCW approved an annual increase of $3.3 million reflecting a return on equity of 10.0 percent and 55 percent equity ratio. Final rates went into effect January 1, 2023.

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.

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 which 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 and Carbon-Free Energy Requirements. On February 7, 2023, the Minnesota Governor signed into law legislation that updates the state’s renewable energy standard and requires Minnesota electric utilities to source retail sales with 100 percent carbon-free energy by 2040. The law increases the renewable energy standard from 25 percent renewable by 2025 to 55 percent renewable by 2035, and requires investor-owned Minnesota utilities to provide 80 percent carbon-free energy by 2030, 90 percent carbon-free energy by 2035 and 100 percent carbon-free energy by 2040. The law utilizes renewable energy credits as the means to demonstrate compliance with both the carbon-free and renewable energy standards, includes an off ramp provision that enables the MPUC to protect reliability and customer costs through modification or delay of either the renewable energy standard, the carbon-free standard, or both, and streamlines development and construction of wind energy projects and transmission in Minnesota. The Company is evaluating the law to identify challenges and opportunities it could present.

As of December 31, 2022, approximately 50 percent of Minnesota Power’s power supply for its retail and municipal customers in Minnesota was provided by renewable energy sources. Minnesota Power’s plans include expanding its renewable energy supply to 70 percent renewable energy by 2030. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

ALLETE, Inc. 2022 Form 10-K

17

REGULATED OPERATIONS (Continued)

Minnesota Legislation (Continued)

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 seven Large Power Customers under contracts of at least 10 MW in 2022, 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 2022, 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 13 other non-affiliated municipal customers are effective through 2029. (See Electric Sales / Customers.)

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 1,200 MW of nameplate capacity wind energy generation with a majority contracted under PSAs of various durations. In addition, ALLETE Clean Energy engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion. ALLETE Clean Energy currently has approximately 100 MW of wind energy facilities under contract to be sold to others. (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, Inc. 2022 Form 10-K

18

ALLETE CLEAN ENERGY (Continued)

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 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	Lake Benton	104	100%	2028
	Storm Lake I	108	100%	2027
	Storm Lake II	77
	Merchant		90%	n/a
	PSA		10%	2032
	Other	17	100%	2028
South	Caddo	303
	Merchant		27%	n/a
	PSA 1		66%	2034
	PSA 2		7%	2034
	Diamond Spring	303
	PSA 1		58%	2035
	PSA 2		25%	2032
	PSA 3		16%	2035
West	Condon	50	100%	(a)
	Glen Ullin	106	100%	2039
	South Peak	80	100%	2035

(a)The PSA for Condon expired in 2022, and Condon is currently selling energy pursuant to a month-to-month agreement while the parties negotiate an agreement on a new PSA.

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.)

CORPORATE AND OTHER

New Energy

On April 15, 2022, a wholly-owned subsidiary of ALLETE acquired 100 percent of the membership interests of New Energy for a purchase price of $165.5 million. New Energy, which is headquartered in Annapolis, Maryland, is a renewable energy development company with a primary focus on solar and storage facilities while also offering comprehensive operations, maintenance and asset management services. New Energy is a leading developer of community, commercial and industrial, and small utility-scale renewable energy projects that has completed more than 400 MW in its history, totaling more than $1 billion of capital deployed. New Energy currently has a robust project pipeline with greater than 2,000 MW of renewable projects in development across 26 different states. New Energy is involved in greenfield development as well as acquiring and completing mid-stage and late-stage renewable energy projects. New Energy will continue its current strategy of developing and operating renewable energy projects.

ALLETE, Inc. 2022 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, 2022, our equity investment in Nobles 2 was $157.3 million ($163.5 million at December 31, 2021). (See Note 6. 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 2027 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, 2022, is approximately $7 million.

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 9. 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, 2022, BNI Energy’s total reclamation liability is estimated at $82.1 million, which is included in Other Non-Current Liabilities on the Consolidated Balance Sheet at its present value. 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 9. Commitments, Guarantees and Contingencies.)

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 300 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, 2022, outstanding finance receivables were $10.5 million, net of reserves, with maturities through 2027. 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, land holdings in Minnesota, and earnings on cash and investments.

As of December 31, 2022, 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 9. 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, the ALLETE Board of Directors Executive Compensation and Human Capital Committee, and our Board of Directors as a whole play key roles in reviewing and overseeing our human capital practices.

As of December 31, 2022, ALLETE had 1,494 employees, of which 1,467 were full-time. We also respect employees’ freedom of association and their right to collectively organize. As of December 31, 2022, Minnesota Power and SWL&P have an aggregate of 484 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.

ALLETE’s Human Rights Statement confirms our commitment to the advancement and protection of human rights, consistent with U.S. human rights laws and the general principles in the International Labour Organization Conventions.

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 Business Conduct that applies to all of our employees, directors of ALLETE, contractors, vendors, and others who do business with or on behalf of ALLETE.

Health and Safety. The success of our business is fundamentally connected to the well-being of our people. 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 hazard identification and controls are discussed to ensure work is being performed safely. Conversations are documented and the data is collected and analyzed for trends. 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.

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HUMAN CAPITAL MANAGEMENT (Continued)

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 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, communications, customers, and ALLETE as a community citizen. ALLETE continues to take 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, 2023, these are the executive officers of ALLETE:

Executive Officers	Initial Effective Date
Bethany M. Owen, Age 57
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
Patrick L. Cutshall, Age 57
Vice President and Corporate Treasurer	December 18, 2017
Nicole R. Johnson, Age 48
Vice President and President of ALLETE Clean Energy	August 22, 2022
Vice President and Chief Administrative Officer	June 28, 2019
Steven W. Morris, Age 61
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
Joshua J. Skelton, Age 43
Vice President and Chief Operating Officer of Minnesota Power	August 22, 2022
Margaret A. Thickens, Age 56
Vice President, Chief Legal Officer and Corporate Secretary	February 13, 2019

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.

Mr. Skelton was Chief Operating Officer of Minnesota Power, Vice President Generation Operations and ALLETE Safety.

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 9, 2023.

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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 29 percent of our 2022 consolidated operating revenue (32 percent in 2021 and 29 percent in 2020) and 36 percent of Regulated Operations operating revenue (37 percent in 2021 and 34 percent in 2020). Minnesota Power’s taconite customers, which are currently owned by only two entities at the end of 2022, accounted for approximately 26 percent of consolidated operating revenue and 32 percent of Regulated Operations operating revenue in 2022. 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 2022 consolidated operating revenue (2 percent in 2021 and in 2020) and 2 percent of Regulated Operations revenue in 2022 (2 percent in 2021 and 3 percent in 2020). 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 demand or 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.

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 or accelerate renewable and carbon-free energy 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. (See Item 1. Business – Regulated Operations – Minnesota Legislation.) 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 2022, our operating coal-fired generating facilities consisted of the 352 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, transmission and distribution 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, transmission and distribution 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, and projects may be delayed or canceled 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 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 sold to our customers, and to other energy suppliers. If transmission capacity is inadequate or transmission and distribution facilities we rely on are damaged, 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 a capacity-constrained area. The ability to restore adequate capacity or repair damaged infrastructure may be impacted by the availability of key materials, supplies, labor and services, which if unavailable may prolong the impact of capacity constraints or damaged facilities. In addition, any infrastructure failure or damage 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 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 certain 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 our 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 energy generation opportunities. In addition, current and potential new project developments at our businesses 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. 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 the acquisition of New Energy, or future acquisitions and 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.

Our results of operations could be adversely affected by changes in governmental incentives or policies that support renewable energy or changes in taxes, tariffs, duties or other assessments on renewable energy or the equipment necessary to generate and deliver it.

Any reductions or modifications to, or the elimination of, governmental incentives or policies that support renewable energy, or the imposition of additional or increased sourcing of components subject to taxes, tariffs, duties or other assessments on renewable energy or the equipment necessary to generate and deliver it, 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 current or future projects.

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Item 1A. Risk Factors (Continued)

ALLETE Clean Energy / Corporate and Other Risks (Continued)

The U.S. government currently imposes antidumping and countervailing duties on certain imported photovoltaic (PV) cells and modules from China and Taiwan. Such duties can change over time pursuant to annual reviews conducted by the U.S. Department of Commerce (DOC). In March 2022, the U.S. DOC launched an investigation into alleged circumvention of these duties by imports of certain PV cells and modules assembled and completed in Cambodia, Malaysia, Thailand, and Vietnam. In June 2022, the U.S. President declared an emergency with respect to threats to electricity generation capacity and authorized the U.S. Secretary of Commerce to consider permitting the importation of certain PV products from those four countries free of antidumping and countervailing duties for 24 months, or until the emergency has terminated. The U.S. DOC has issued final regulations designed to implement that moratorium in the event that it finds circumvention in its ongoing inquiries. We cannot predict what further actions the U.S. DOC will take with respect to these circumvention inquiries. Our operating results could be adversely impacted if the U.S. DOC makes circumvention determinations that result in duties assessed on future purchases made by our businesses after the moratorium ends.

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 and different settlement prices between hub and node 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 C&I customers at its Diamond Spring and Caddo wind energy facilities are contracts for differences where power is delivered to the market, 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. Certain contracts also settle with the market at the hub price whereas ALLETE Clean Energy settles with the customer at the node price which can vary significantly based on multiple factors. These settlement provisions can result in an adverse impact on our financial position, results of operations and cash flows when market prices are volatile.

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Item 1A. Risk Factors (Continued)

ALLETE Clean Energy / Corporate and Other Risks (Continued)

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 that expire in various years between 2024 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.

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.

ALLETE has a significant amount of goodwill. A determination that goodwill has been impaired could result in a significant non-cash charge to earnings.

We had approximately $155 million of goodwill recorded on our Consolidated Balance Sheet as of December 31, 2022 related to New Energy. If we change our business strategy, fail to deliver on our projected results or if market or other conditions adversely affect the operations of New Energy, we may be required to record an impairment charge. Declines in projected operating cash flows at New Energy could also result in 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.

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.

Health epidemics, pandemics and other outbreaks, as well as the related federal and state government responses, can have widespread impacts on the economy and on our employees, customers, contractors and suppliers, such as those experienced from the ongoing COVID-19 pandemic. There may be uncertainty regarding the length of time an epidemic, pandemic or other outbreak will last, how they will evolve, or the extent and duration of any measures attempted to try and contain them.

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

A disruption of economic activity or an extended disruption of economic activity may lead to 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. A disruption in capital markets could lead to increased borrowing costs or adversely impact our ability to access capital markets or other financing sources, which would adversely affect our ability to maintain our businesses or to implement our business plans. An epidemic, pandemic or other outbreak may also result in a disruption to our supply chains which could adversely impact our operations and capital projects resulting in project and operational delays, project cancellations, lower returns on projects and cost increases.

Despite any efforts made to mitigate the impacts on the Company of an epidemic, pandemic or other outbreak, their ultimate impact also depends on factors beyond our control, including their duration and severity as well as governmental and third-party actions taken to contain their spread and mitigate their public health effects. As a result, we cannot predict the ultimate impact of an epidemic, pandemic or other outbreak, such as the ongoing 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. Rising interest rates, inflation and 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. This would include our ability to make the significant capital expenditures planned in order to achieve Minnesota Power’s clean-energy transition plans. (See Item 7. Capital Requirements.)

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, regional or global level, it may have a negative impact on our customers and the Company’s financial position, results of operations and cash flows. 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.

Our utility infrastructure and generating facilities, ongoing and future capital and development projects, and other operations require components, supplies, materials, labor and services sourced from suppliers or providers who, in turn, may source components from their suppliers. A shortage of key components, supplies, materials, labor or services in which an alternative supplier or provider is not identified could significantly impact project plans or our operations. Such impacts could include project delays, including potential for project cancellation, lower project returns, increased costs or the inability to provide service to customers, which could adversely impact our results of operations, financial condition or cash flows.

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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, operations that produce or enable the production of GHG emissions or other events which may result in negative customer perception, increased regulatory oversight, and negative consequences to our credit ratings and ability to access capital, 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, increased risk of wildfires, 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 used in our operations or to respond to damaged facilities. 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, the ability of our regulated businesses to obtain rate adjustments to recover costs and investments to implement clean-energy transition plans, or disruptions to the economy or energy markets caused by climate change. 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 9. 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.

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 $0.6775 per share on our common stock is payable on March 1, 2023, to the shareholders of record on February 15, 2023. 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, 2023, 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, 2017, and reinvestment of dividends.

	2017	2018	2019	2020	2021	2022
ALLETE	$100	$106	$116	$92	$102	$104
S&P 500 Index	$100	$96	$126	$149	$192	$157
Philadelphia Utility Index	$100	$104	$131	$135	$159	$160

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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.

Overview

Basis of Presentation. We present two reportable segments: Regulated Operations and ALLETE Clean Energy. 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 14 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 1,200 MW of nameplate capacity wind energy generation with a majority contracted under PSAs of various durations. In addition, 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 Clean Energy currently has approximately 100 MW of wind energy facilities under contract to be sold to others.

Corporate and Other is comprised of New Energy, a renewable development company; 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; BNI Energy, our coal mining operations in North Dakota; 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; land holdings 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, 2022, 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.

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2022 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2022 to the year ended December 31, 2021.

Net income attributable to ALLETE in 2022 was $189.3 million, or $3.38 per diluted share, compared to $169.2 million, or $3.23 per diluted share, in 2021. Net income in 2022 included higher earnings at Minnesota Power resulting from the implementation of interim rates on January 1, 2022, net of interim rate reserves, and also included net income of $7.8 million from New Energy, which was acquired in April 2022. These increases were partially offset by lower earnings from ALLETE Clean Energy reflecting challenges under the Caddo and Diamond Spring wind energy facilities’ power sales agreements and additional losses related to the sale of the Northern Wind project. Net income in 2021 included South Shore Energy’s sale of a portion of its interest in NTEC to Basin Electric Cooperative and the resulting 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. Earnings per share dilution in 2022 was $0.23 due to additional shares of common stock outstanding as of December 31, 2022.

Regulated Operations net income attributable to ALLETE was $149.9 million in 2022, compared to $129.1 million in 2021. Net income at Minnesota Power was higher than 2021 primarily due to the implementation of interim rates on January 1, 2022, net of interim rate reserves. This increase was partially offset by higher costs under a PPA with Manitoba Hydro, higher operating and maintenance expense, and lower kWh sales to industrial customers. Our after-tax equity earnings in ATC were lower than 2021 primarily due to period over period changes in ATC’s estimate of a refund liability related to the appeals court decision on MISO return on equity complaints. (See Note 6. Equity Investments.)

ALLETE Clean Energy net income attributable to ALLETE was $16.3 million in 2022 compared to $26.3 million in 2021. Net income in 2022 reflected challenges under the Caddo and Diamond Spring wind energy facilities’ power sales agreements resulting from extreme market volatility and transmission congestion in the Southwest Power Pool. Net income in 2022 also included additional losses related to the sale of the Northern Wind project. 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.

Corporate and Other net income attributable to ALLETE was $23.1 million in 2022 compared to $13.8 million in 2021. Net income in 2022 reflects net income from New Energy of $7.8 million, which included a $8.3 million after-tax expense as a result of purchase price accounting related to projects under development at the time of acquisition. Net income in 2022 also reflects higher earnings from our investment in Nobles 2 due to higher wind resources in 2022, higher land sales at ALLETE Properties, earnings from Minnesota solar projects placed into service in 2022 and lower income taxes. These increases were partially offset by transaction costs of $2.7 million after-tax related to the acquisition of New Energy, and higher other expenses compared to 2021. Net income in 2021 included South Shore Energy’s sale of a portion of its interest in NTEC to Basin which resulted in the recognition of an approximately $8.5 million after-tax gain related to prior development costs and risks incurred.

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2022 Compared to 2021

(See Note 14. Business Segments for financial results by segment.)

Regulated Operations

Year Ended December 31	2022	2021
Millions
Operating Revenue – Utility	$1,259.3	$1,227.9
Fuel, Purchased Power and Gas – Utility	545.5	562.4
Transmission Services – Utility	76.7	75.3
Operating and Maintenance	239.3	216.0
Depreciation and Amortization	171.9	170.7
Taxes Other than Income Taxes	57.4	60.9
Operating Income	168.5	142.6
Interest Expense	(58.1)	(57.3)
Equity Earnings	19.3	21.3
Other Income	9.8	5.9
Income Before Income Taxes	139.5	112.5
Income Tax Benefit	(10.4)	(16.6)
Net Income Attributable to ALLETE	$149.9	$129.1

Operating Revenue – Utility increased $31.4 million from 2021 primarily due to the implementation of interim rates at Minnesota Power on January 1, 2022, as well as increased recoveries under the Minnesota conservation improvement program and higher gas sales. These increases were partially offset by lower revenue from kWh sales and lower fuel adjustment clause recoveries.

Interim retail rate revenue of $85.5 million was collected in 2022, which was partially offset by an interim rate refund reserve of approximately $18 million due to the regulatory outcome of the MPUC’s decision in Minnesota Power’s 2022 general rate case. In addition, Minnesota Power recorded a charge of approximately $8 million pre-tax to write off the deferred portion of residential customer interim rates. Minnesota Power also recorded additional revenue of approximately $9 million pre-tax for an increase in expected recoveries under its cost recovery riders. (See Note 4. Regulatory Matters.)

Conservation improvement program recoveries increased $5.9 million from 2021 primarily due to an increase in related expenditures. (See Operating Expenses - Operating and Maintenance.)

Gas sales at SWL&P increased $4.6 million as a result of colder weather and higher gas prices in 2022 compared to 2021. (See Fuel, Purchased Power and Gas – Utility.)

Lower kWh sales reduced revenue $27.4 million from 2021 reflecting lower sales to industrial customers and other power suppliers, partially offset by higher sales to residential and commercial customers as well as higher pricing on sales to other power suppliers. Sales to residential and commercial customers increased from 2021 primarily due to colder weather in 2022 compared to 2021. Sales to industrial customers decreased primarily due to lower sales to taconite customers resulting from less taconite production in 2022 compared to 2021, reflecting Cliffs’ Northshore mine being temporarily idled in 2022. (See Outlook - Customers - Northshore Mining.) 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, decreased in 2022 compared to 2021 primarily due to additional kWh sales made in 2021 to mitigate the uncertainty of customers’ energy needs and potential load loss due to the COVID-19 pandemic.

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2022 Compared to 2021 (Continued)

Regulated Operations (Continued)

Kilowatt-hours Sold	2022	2021	Quantity Variance	% Variance
Millions
Regulated Utility
Retail and Municipal
Residential	1,148	1,135	13	1.1
Commercial	1,359	1,359	—	—
Industrial	6,745	7,196	(451)	(6.3)
Municipal	540	590	(50)	(8.5)
Total Retail and Municipal	9,792	10,280	(488)	(4.7)
Other Power Suppliers	3,149	5,102	(1,953)	(38.3)
Total Regulated Utility Kilowatt-hours Sold	12,941	15,382	(2,441)	(15.9)

Revenue from electric sales to taconite customers accounted for 32 percent of regulated operating revenue in 2022 (33 percent in 2021). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of regulated operating revenue in 2022 (5 percent in 2021). Revenue from electric sales to pipelines and other industrial customers accounted for 10 percent of regulated operating revenue in 2022 (9 percent in 2021).

Fuel adjustment clause revenue decreased $24.1 million primarily due to lower kWh sales, partially offset by higher fuel and purchased power costs attributable to retail and municipal customers. (See Fuel, Purchased Power and Gas – Utility.) Fuel adjustment clause revenue in 2021 also reflected a $5 million charge recorded in 2021 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.)

Operating Expenses increased $5.5 million from 2021.

Operating and Maintenance expense increased $23.3 million, or 11 percent, from 2021 primarily due to higher conservation improvement program expenses, professional services and materials purchased for generation facilities, labor expenses and higher vegetation management expenses. These increases were partially offset by lower pension and other postretirement benefit expenses. In addition, 2022 included rate case-related expenses for Minnesota Power’s rate case. (See Note 4. Regulatory Matters.)

Transmission Services – Utility expense increased $1.4 million, or 2 percent, from 2021 primarily due to higher MISO-related expense.

Depreciation and Amortization expense increased $1.2 million, or 1 percent, from 2021 primarily due to a higher plant in service balance in 2022.

Fuel, Purchased Power and Gas – Utility expense decreased $16.9 million, or 3 percent, from 2021 primarily due to lower energy purchases due to lower kWh sales, partially offset by higher purchased power prices and fuel prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.

Taxes Other than Income Taxes decreased $3.5 million, or 6 percent, from 2021 primarily due to lower property tax expense resulting from an updated estimate of taxable market values and rates in 2022.

Equity Earnings decreased $2.0 million from, or 9 percent, 2021 primarily due to period over period changes in ATC’s estimate of a refund liability related to the appeals court decision on MISO return on equity complaints. (See Note 6. Equity Investments.)

Other Income increased $3.9 million from 2021 primarily due to lower pension and other postretirement plan non-service credits. (See Note 1. Operations and Significant Accounting Policies.)

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2022 Compared to 2021 (Continued)

Regulated Operations (Continued)

Income Tax Benefit decreased $6.2 million from 2021 primarily due to higher pre-tax income and lower production tax credits.

ALLETE Clean Energy

Year Ended December 31	2022	2021
Millions
Operating Revenue
Contracts with Customers – Non-utility	$110.7	$75.5
Other – Non-utility (a)	7.6	11.4
Cost of Sales – Non-utility	56.7	3.0
Operating and Maintenance	47.3	41.5
Depreciation and Amortization	58.6	49.2
Taxes Other than Income Taxes	10.7	7.1
Operating Loss	(55.0)	(13.9)
Interest Expense	(2.3)	(1.5)
Other Income	10.8	0.3
Loss Before Income Taxes	(46.5)	(15.1)
Income Tax Benefit	(15.4)	(16.6)
Net Income (Loss)	(31.1)	1.5
Net Loss Attributable to Non-Controlling Interest (b)	(47.4)	(24.8)
Net Income Attributable to ALLETE	$16.3	$26.3

(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 $31.4 million, or 36 percent, from 2021 primarily due to revenue from the closing of a portion of ALLETE Clean Energy’s Northern Wind project in December 2022. Operating revenue in 2022 was also impacted by lower realized pricing under the Caddo and Diamond Spring wind energy facilities’ power sales agreements resulting from extreme market volatility and transmission congestion in the Southwest Power Pool. Operating revenue in 2021 included the negative impact related to ALLETE Clean Energy’s Diamond Spring wind energy facility resulting from an extreme winter storm event in the southwest United States in February 2021.

	Year Ended December 31,
	2022		2021
Production and Operating Revenue	kWh	Revenue	kWh	Revenue
Millions
Wind Energy Regions
East	266.6	$24.3	236.6	$21.4
Midwest (a)	775.9	27.0	882.9	32.2
South	2,047.1	15.4	1,009.8	11.2
West	829.5	18.1	823.2	22.1
Total Wind Energy Facilities	3,919.1	84.8	2,952.5	86.9
Sale of Wind Energy Facility	—	33.5	—	—
Total Production and Operating Revenue	3,919.1	$118.3	2,952.5	$86.9

(a)The Chanarambie and Viking wind energy facilities were decommissioned in the second quarter of 2022 as part of ALLETE Clean Energy’s Northern Wind project.

Cost of Sales - Non-utility increased $53.7 million from 2021 reflecting additional losses in 2022 related to ALLETE Clean Energy’s project to repower and sell its Northern Wind project resulting from inflationary increases and significant cost pressures. In addition, Cost of Sales – Non-utility in 2022 reflected a $10.2 million reserve in the second quarter of 2022 related to the sale of the Northern Wind project, which was fully offset by a gain on removal of the PSA liability for the Northern Wind project upon decommissioning of the wind energy facilities. (See Other Income and Outlook – ALLETE Clean Energy.)

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2022 Compared to 2021 (Continued)

ALLETE Clean Energy (Continued)

Operating and Maintenance expense increased $5.8 million, or 14 percent, from 2021 primarily due to operating and maintenance expenses related to the Caddo wind energy facility, which commenced operations in December 2021.

Depreciation and Amortization expense increased $9.4 million, or 19 percent, from 2021 primarily due to additional property, plant and equipment in service related to the Caddo wind energy facility, which commenced operations in December 2021.

Taxes Other Than Income Taxes increased $3.6 million from 2021 primarily due to higher property tax expense related to the Caddo wind energy facility, which commenced operations in December 2021.

Other Income increased $10.5 million from 2021 primarily due to a gain on removal of the PSA liability for the Northern Wind project upon decommissioning of the wind energy facilities. (See Cost of Sales – Non-utility and Outlook – ALLETE Clean Energy.)

Net Loss Attributable to Non-Controlling Interest increased $22.6 million from 2021 reflecting net losses attributable to non-controlling interest for the Caddo wind energy facility as well as higher net losses attributable to non-controlling interests for the Glen Ullin and Diamond Spring wind energy facilities resulting from higher wind resources and a higher PTC value in 2022 compared to 2021.

Corporate and Other

Operating Revenue increased $88.7 million, or 85 percent, from 2021 reflecting revenue from New Energy, which was acquired in April 2022, higher revenue at BNI Energy which operates under cost-plus fixed fee contracts, as a result of higher expenses in 2022 compared to 2021 and higher land sales at ALLETE Properties compared to 2021.

Net Income Attributable to ALLETE was $23.1 million in 2022 compared to $13.8 million in 2021. Net income in 2022 reflects net income from New Energy of $7.8 million, which included a $8.3 million after-tax expense as a result of purchase price accounting related to projects under development at the time of acquisition. Net income in 2022 also reflects higher earnings from our investment in Nobles 2 due to higher wind resources in 2022, higher land sales at ALLETE Properties, earnings from Minnesota solar projects placed into service in 2022 and lower income taxes. These increases were partially offset by transaction costs of $2.7 million after-tax related to the acquisition of New Energy, and higher other expenses compared to 2021. Net income in 2021 included South Shore Energy’s sale of a portion of its interest in NTEC to Basin which resulted in the recognition of an approximately $8.5 million after-tax gain related to prior development costs and risks incurred.

Income Taxes – Consolidated

For the year ended December 31, 2022, the effective tax rate was a benefit of 31.2 percent (benefit of 24.3 percent for the year ended December 31, 2021). The effective tax rate for 2022 was a lower benefit primarily due to lower production tax credits, higher pre-tax income and higher net losses attributable to non-controlling interests in subsidiaries. (See Note 11. Income Tax Expense.)

2021 Compared to 2020

The comparison of the results of operations for the years ended December 31, 2021 and 2020 is included in Management's Discussion in the Annual Report on Form 10-K for the year ended December 31, 2021. We have identified an immaterial prior period error with respect to the recognition of a non-cash impairment expense for our Northern Wind operating assets in 2020, and the prior period results have been revised accordingly for comparability. See Note 1. Operations and Significant Accounting Policies for additional information.

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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.)

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, 2022, was approximately 46 percent equity securities, 50 percent fixed income and 4 percent real estate. Our postretirement health and life asset allocation as of December 31, 2022, was approximately 66 percent equity securities, and 34 percent fixed income. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2022, we used weighted average expected long-term rates of return of 6.00 percent in our actuarial determination of our pension expense and 5.41 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 $2.2 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 2022, we used weighted average discount rates of 3.28 percent and 3.09 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 $1.0 million, pre-tax.

The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2022, considered a modified PRI-2012 mortality table and MP-2021 mortality projection scale. (See Note 12. Pension and Other Postretirement Benefit Plans.)

Valuation of Business Combinations and Resulting Goodwill. When we acquire a business, the assets acquired and liabilities assumed are recorded at their respective fair values as of the acquisition date. Determining the fair value of intangible assets acquired as part of a business combination requires us to make significant estimates. These estimates may include the amount and timing of projected future cash flows, the discount rate used to discount those cash flows to present value, the assessment of the asset’s life cycle, and the consideration of legal, technical, regulatory, economic and competitive risks.

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Critical Accounting Policies (Continued)

Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of the net assets of the acquired businesses. In accordance with GAAP, goodwill is not amortized. The Company assesses whether there has been an impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. Our estimates associated with the goodwill impairment test are considered critical due to the amount of goodwill recorded on our Consolidated Balance Sheet and the judgment required in determining fair value. The fair value of the New Energy reporting unit was determined using a discounted cash flow model, using significant assumptions which included a discount rate of 14 percent, cash flow forecasts through 2027, industry average gross margins, and a terminal growth rate of 3.5 percent. Any forecast contains a degree of uncertainty, and changes in the forecasted cash flows and other assumptions could significantly increase or decrease the calculated fair value of New Energy. The results of our annual impairment test are discussed in Note 1. Operations and Significant Accounting Policies and Note 7. Fair Value in this Form 10-K. Goodwill was $154.9 million as of December 31, 2022.

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 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, New 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 2023. ALLETE expects its businesses to generally provide regulated, contracted or recurring revenues, and to support sustained growth in net income and cash flow.

On August 16, 2022, the Inflation Reduction Act was signed into law. We believe our businesses will benefit from certain provisions of the legislation including from the extension and transferability of production tax credits and investment tax credits, among others. We do not anticipate any impact from the new alternative minimum tax. We will continue to assess the impact of the legislation as additional implementation guidance becomes available.

Minnesota Carbon-Free Legislation. On February 7, 2023, the Minnesota Governor signed into law legislation that updates the state’s renewable energy standard and requires Minnesota electric utilities to source retail sales with 100 percent carbon-free energy by 2040. The law increases the renewable energy standard from 25 percent renewable by 2025 to 55 percent renewable by 2035, and requires investor-owned Minnesota utilities to provide 80 percent carbon-free energy by 2030, 90 percent carbon-free energy by 2035 and 100 percent carbon-free energy by 2040. The law utilizes renewable energy credits as the means to demonstrate compliance with both the carbon-free and renewable standards, includes an off-ramp provision that enables the MPUC to protect reliability and customer costs through modification or delay of either the renewable energy standard, the carbon-free standard, or both, and streamlines development and construction of wind energy projects and transmission in Minnesota. The Company is evaluating the law to identify challenges and opportunities it could present.

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.

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Outlook (Continued)

Regulatory Matters (Continued)

At a hearing on January 23, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. Upon commencement of final rates, we expect additional revenue from base rates of approximately $60 million and an additional $10 million in revenue recognized under cost recovery riders on an annualized basis, subject to final written order and reconsideration. Final rates are expected to commence in the third quarter of 2023; interim rates will be collected through this period with reserves recorded as necessary. As a result of the MPUC’s determinations made on January 23, 2023, Minnesota Power has recorded a reserve for an interim rate refund of approximately $18 million pre-tax as of December 31, 2022, which is subject to MPUC approval of Minnesota Power’s refund calculation. In addition, Minnesota Power recorded a charge of approximately $8 million pre-tax to write-off the deferred portion of residential customer interim rates. Minnesota Power also recorded additional revenue of approximately $9 million pre-tax for an increase in expected recoveries under its cost recovery riders. Minnesota Power plans to file its next rate case in the fourth quarter of 2023.

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.

2022 Wisconsin General Rate Case. In 2022, SWL&P filed a rate increase request with the PSCW seeking an average increase of 3.6 percent for retail customers. The filing sought an overall return on equity of 10.4 percent and a 55 percent equity ratio. On an annualized basis, the requested final rate increase would have generated an estimated $4.3 million in additional revenue. In an order dated December 20, 2022, the PSCW approved an annual increase of $3.3 million reflecting a return on equity of 10.0 percent and 55 percent equity ratio. Final rates went into effect January 1, 2023.

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 52 percent of our regulated utility kWh sales in 2022 (47 percent in 2021 and 47 percent in 2020) were made to our industrial customers. We expect industrial sales of approximately 6.5 million MWh in 2023 (6.7 million MWh in 2022 and 7.2 million in 2021). (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 78 percent of capacity in 2022 (82 percent in 2021 and 68 percent in 2020). 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 2023 will increase by approximately 2 percent compared to 2022.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

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 33 million tons in 2023. 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. USS Corporation has announced plans to invest approximately $150 million to construct a system dedicated to producing direct reduced-grade (DR-grade) pellets at its Keetac plant. USS Corporation broke ground on the project in the third quarter of 2022, which is expected to be completed and producing DR-grade pellets in 2024. This will enable the existing pelletizing plant to not only create DR-grade pellets for use as a feedstock for a direct reduced iron (DRI) or hot briquetted iron (HBI) process that ultimately supplies electric arc furnace steelmaking but also maintains the optionality to continue producing blast furnace-grade pellets. USS Corporation’s Minntac and Keetac plants are large power industrial customers of Minnesota Power. USS Corporation has the capability to produce approximately 15 million and 5 million tons annually at its Minntac and Keetac plants, respectively.

Cleveland-Cliffs, Inc. (Cliffs). In 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 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 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.).

Northshore Mining. On February 11, 2022, Cliffs announced that with the use of additional scrap in its basic oxygen furnaces, its iron ore needs are not as high as before. In determining where to adjust production, Cliffs decided to idle all production at its Northshore mine until at least April 2023. Cliffs has 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 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 2019, Silver Bay Power ceased self-generation and Minnesota Power began supplying the full energy requirements for Silver Bay Power.

Hibbing Taconite. Hibbing Taconite is a joint venture between subsidiaries of Cliffs (85.3 percent ownership) and USS Corporation (14.7 percent ownership). The joint venture is managed by Cliffs and is also a Large Power Customer of Minnesota Power. Hibbing Taconite has the capability of producing 8 million tons of taconite annually. Hibbing Taconite has proven mineral reserves to support its operations through 2026; and is actively seeking additional mineral reserves to operate beyond its currently stated mine life.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

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 continues to face 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. The resulting reduction in production capacity outside of Minnesota for certain paper grades has solidified our paper customers’ operations, at least for the near term, and as such we expect operating levels in 2023 at the major paper and pulp mills we serve to be at similar levels as in 2022.

ST Paper. In May 2021, ST Paper announced it had completed the purchase of the Duluth Mill from Verso Corporation. ST Paper is completing a project at the Duluth Mill to produce tissue. In January 2022, Minnesota Power entered into an electric service agreement with ST Paper that would begin Large Power Customer service with a minimum term of six years upon start-up of operations, which is anticipated in 2023. A petition for approval of the electric service agreement was approved by the MPUC in May 2022. Upon start-up of operations, ST Paper will become a Large Power Customer 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 expected to resume normal operations in 2023.

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.

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 (IRP). On February 1, 2021, Minnesota Power filed its latest IRP, which was approved by the MPUC in an order dated January 9, 2023. The approved IRP, which reflects a joint agreement reached with various stakeholders, outlines Minnesota Power’s 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 up to 700 MW of new wind and solar energy resources, and ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. 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. Minnesota Power is expected to file its next IRP by March 1, 2025.

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.

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Outlook (Continued)

EnergyForward (Continued)

Nemadji Trail Energy Center (NTEC). 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.)

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 two long-term PPAs with Manitoba Hydro. The first PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro through May 2035. The second PPA provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro through June 2040. (See Note 9. 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 2023 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 commenced in 2022 and will be operational in 2023.

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 9. Commitments, Guarantees and Contingencies.

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Outlook (Continued)

Transmission (Continued)

North Plains Connector Development Agreement. ALLETE and Grid United LLC, an independent transmission company, have signed a memorandum of understanding to explore transmission opportunities, with plans to execute a North Plains Connector development agreement in the first half of 2023. The project is a new, approximately 385-mile high-voltage direct-current (HVDC) transmission line from central North Dakota, to Colstrip, Montana that will be the first transmission connection between three regional U.S. electric energy markets— MISO, the Western Interconnection and the Southwest Power Pool. This new link, open to all sources of electric generation, would create 3,000 MW of transfer capacity between the middle of the country and the West Coast, easing congestion on the transmission system, increasing resiliency and reliability in all three energy markets, and enabling fast sharing of renewable energy across a vast area with diverse weather patterns. The project is expected to cost approximately $2.5 billion. ALLETE expects to pursue at least 35 percent ownership and would oversee the line’s operation. The companies expect project permitting to start in 2023 as they work toward an in-service date of 2029, pending regulatory approvals.

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. A certificate of need and route permit are expected in first quarter of 2023. 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.

MISO Long Range Transmission Plan. Minnesota Power and Great River Energy announced on July 25, 2022, their intent to build a 150-mile, 345-kV transmission line, connecting northern Minnesota to central Minnesota to support continued reliability in the Upper Midwest. Great River Energy, a wholesale electric power cooperative, and Minnesota Power filed a Notice of Intent to Construct, Own and Maintain the transmission line with the MPUC on August 1, 2022. This joint project is part of a portfolio of transmission projects approved on July 25, 2022, by MISO, as part of the first phase of its Long Range Transmission Plan. Planning for the $970 million transmission line is in its early stages with the route anticipated to generally follow existing rights of way in an established power line corridor. The two utilities expect to seek a combined Certificate of Need and Route Permit from the MPUC. The MPUC will determine the final route as well as cost recovery for Minnesota Power’s approximately 50 percent estimated share of the project. Subject to regulatory approvals, the transmission line is expected to be in service in 2030.

Investment in ATC. ATC’s most recent 10-year transmission assessment, which covers the years 2022 through 2031, identifies a need for between $5.1 billion and $6.2 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.

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 is focused on actions that will optimize its clean energy project portfolio of operating and development projects, which may include recontracting, repowering, entering into partnerships and divestitures along with continued acquisitions or development of new projects including wind, solar, energy storage or storage ready facilities across North America.

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 wind, 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.

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Outlook (Continued)

ALLETE Clean Energy (Continued)

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.

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	Lake Benton	104	100%	2028
	Storm Lake I	108	100%	2027
	Storm Lake II	77
	Merchant		90%	n/a
	PSA 1		10%	2032
	Other	17	100%	2028
South	Caddo	303
	Merchant		27%	n/a
	PSA 1		66%	2034
	PSA 2		7%	2034
	Diamond Spring	303
	PSA 1		58%	2035
	PSA 2		25%	2032
	PSA 3		16%	2035
West	Condon	50	100%	(a)
	Glen Ullin	106	100%	2039
	South Peak	80	100%	2035

(a)The PSA for Condon expired in 2022, and Condon is currently selling energy pursuant to a month-to-month agreement while the parties negotiate an agreement on a new PSA.

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 $5 million in 2023, $6 million annually in 2024 through 2027, and decreasing thereafter through 2032.

Corporate and Other.

New Energy. New Energy is a renewable energy development company with a primary focus on solar and storage facilities while also offering comprehensive operations, maintenance and asset management services. New Energy is a leading developer of community, commercial and industrial, and small utility-scale renewable energy projects that has completed more than 400 MW in its history, totaling more than $1 billion of capital deployed. New Energy currently has a robust project pipeline with greater than 2,000 MW of renewable projects in development across 26 different states. New Energy adds value through cost effective development and economies of scale on project implementation, bringing national capabilities to regional co-development partners. New Energy is involved in greenfield development as well as acquiring and completing mid-stage and late-stage renewable energy projects.

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 6. 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 2027 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, 2022, is approximately $7 million.

BNI Energy. In 2022, BNI Energy sold 3.7 million tons of coal (3.9 million tons in 2021) and anticipates 2023 sales will be higher than 2022. BNI Energy operates under cost-plus fixed fee agreements extending through December 31, 2037.

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 2022. 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 2023 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. As of December 31, 2022, we had cash and cash equivalents of $36.4 million, $411.6 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 37 percent.

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

As of December 31	2022	%	2021	%	2020	%
Millions
ALLETE Equity (a)	$2,691.9	51	$2,404.3	49	$2,285.8	50
Non-Controlling Interest in Subsidiaries	656.4	12	533.2	11	505.6	11
Short-Term and Long-Term Debt (b)	1,929.1	37	1,986.4	40	1,806.4	39
	$5,277.4	100	$4,923.9	100	$4,597.8	100

(a) See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

(b) Excludes unamortized debt issuance costs.

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

Year Ended December 31	2022	2021	2020
Millions
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$47.7	$65.2	$92.5
Cash Flows from (used in)
Operating Activities	221.3	263.5	299.8
Investing Activities	(384.0)	(485.2)	(812.8)
Financing Activities	155.2	204.2	485.7
Change in Cash, Cash Equivalents and Restricted Cash	(7.5)	(17.5)	(27.3)
Cash, Cash Equivalents and Restricted Cash at End of Period	$40.2	$47.7	$65.2

Operating Activities. Cash provided by operating activities was lower in 2022 compared to 2021. Cash provided by operating activities in 2022 reflected higher payments for inventories, net of customer deposits received, compared to 2021 primarily related to ALLETE Clean Energy’s Northern Wind and Red Barn projects. This decrease was partially offset by the timing of recovery under the fuel adjustment clause.

Cash provided by 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 under the fuel adjustment clause.

Investing Activities. Cash used in investing activities was lower in 2022 compared to 2021. Cash used for investing activities in 2022 reflected lower additions to property, plant and equipment and lower payments for equity method investments compared to 2021. These decreases were partially offset by cash payments for the acquisition of New Energy.

Cash used in 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.

Financing Activities. Cash provided by financing activities was lower in 2022 compared to 2021 primarily due to higher repayments of short-term and long-term debt and higher dividends on common stock in 2022. These decreases were partially offset by higher proceeds from the issuance of common stock, higher proceeds from issuance of short-term and long-term debt, and higher proceeds from non-controlling interest in 2022.

Cash provided by 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)

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, 2022, we had consolidated bank lines of credit aggregating $475.7 million ($432.0 million as of December 31, 2021), most of which expire in January 2026. We had $32.8 million outstanding in standby letters of credit and $31.3 million outstanding draws under our lines of credit as of December 31, 2022 ($31.5 million in standby letters of credit and $159.7 million outstanding draws as of December 31, 2021). We also have other credit facility agreements in place that provide the ability to issue up to $252.0 million in standby letters of credit. As of December 31, 2022, we had $245.4 million outstanding in standby letters of credit under these agreements.

In addition, as of December 31, 2022, we had 2.9 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, 2022. For the year ended December 31, 2022, no shares of common stock were issued under this agreement (0.8 million shares for net proceeds of $51.0 million in 2021; none in 2020).

During the year ended December 31, 2022, 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 $16.2 million (0.3 million shares for net proceeds of $18.9 million in 2021; 0.4 million shares for net proceeds of $18.1 million in 2020). See Note 10. Common Stock and Earnings Per Share for additional detail regarding ALLETE’s equity securities.

On April 5, 2022, ALLETE issued and sold approximately 3.7 million shares of ALLETE common stock. Net proceeds of approximately $224 million were received from the sale of shares. Proceeds were used primarily to fund the acquisition of New Energy and capital investments at ALLETE Clean Energy.

Financial Covenants. See Note 8. 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, 2022, we made no contributions to the defined benefit pension plans. On January 17, 2023, we contributed $6.5 million in cash to the defined benefit pension plans. We do not expect to make any further contributions to our defined benefit pension plans in 2023, and we do not expect to make any contributions to our other postretirement benefit plans in 2023. (See Note 10. Common Stock and Earnings Per Share and Note 12. Pension and Other Postretirement Benefit Plans.)

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 9. Commitments, Guarantees and Contingencies.

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 8. 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 12. Pension and Other Postretirement Benefit Plans.)

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Liquidity and Capital Resources (Continued)

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 9. Commitments, Guarantees and Contingencies.)

PPA Obligations. PPA obligations represent our Square Butte, Manitoba Hydro and other PPAs. (See Note 9. 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 9. 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 2022, we paid out 77 percent (78 percent in 2021; 78 percent in 2020) of our per share earnings in dividends. On February 3, 2023, our Board of Directors declared a dividend of $0.6775 per share, which is payable on March 1, 2023, to shareholders of record at the close of business on February 15, 2023.

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Capital Requirements

ALLETE’s projected capital expenditures for the years 2023 through 2027 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		2023	2024	2025	2026	2027	Total
Millions
Regulated Operations
	High kV Transmission Expansion	$40	$55	$135	$190	$270	$690
	Solar 300 MW (a)	—	150	200	175	100	625
	Wind 150 MW (a)	—	—	105	175	—	280
	Storage (a)	—	10	20	—	100	130
	Base & Other	190	265	250	235	190	1,130
Regulated Operations		$230	$480	$710	$775	$660	$2,855
ALLETE Clean Energy (b)		10	5	5	5	5	30
Corporate and Other
	South Shore Energy (c)	40	55	35	5	—	135
	Other	20	10	15	15	20	80
Total Capital Expenditures (d)		$300	$550	$765	$800	$685	$3,100

(a)These capital expenditures are part of Minnesota Power’s clean-energy transition plans, which include its vision to deliver 100 percent carbon-free energy to customers by 2050, as detailed in Minnesota Power’s latest IRP, which was approved by the MPUC in January 2023. These capital expenditures are dependent on successful requests for proposal by Minnesota Power. (See Outlook – EnergyForward.)

(b)Capital expenditures in 2023 do not include costs related to ALLETE Clean Energy’s project to develop and sell the 92 MW Red Barn project as these projects will be sold upon completion. (See Outlook – ALLETE Clean Energy.)

(c)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.

(d)These amounts do not include any capital expenditures related to the North Plains Connector Development Agreement. (See Outlook – Transmission.)

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 9. Commitments, Guarantees and Contingencies.)

Market Risk

Securities Investments.

Available-for-Sale Securities. As of December 31, 2022, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.

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Market Risk (Continued)

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, 2022:

	Expected Maturity Date
Interest Rate Sensitive Financial Instruments	2023	2024	2025	2026	2027	Thereafter	Total	Fair Value
Long-Term Debt
Fixed Rate – Millions	$91.9	$87.3	$216.1	$79.4	$81.7	$1,154.4	$1,710.8	$1,564.4
Average Interest Rate – %	5.9	4.4	3.4	3.4	5.7	4.0	4.1
Variable Rate – Millions	—	$7.5	$170.0	—	$40.8	—	$218.3	$218.3
Average Interest Rate – %	—	7.8	4.8	—	4.2	—	4.8

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, 2022, an increase of 100 basis points in interest rates would impact the amount of pre-tax interest expense by $2.2 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, 2022.

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.

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.

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Item 8. Financial Statements and Supplementary Data

See our Consolidated Financial Statements as of December 31, 2022 and 2021, and for the years ended December 31, 2022, 2021 and 2020, 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, 2022, 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, 2022.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

On April 15, 2022, the Company completed the acquisition of New Energy. As a result, management has excluded New Energy from our assessment of internal control over financial reporting. New Energy is a wholly-owned subsidiary whose total assets and total revenues represent 1 percent and 5 percent, respectively, of the related Consolidated Financial Statement amounts as of and for the year ended December 31, 2022.

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 2023 Annual Meeting of Shareholders (2023 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 2023 Proxy Statement will be filed with the SEC within 120 days after the end of our 2022 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 Committee Report,” the “Director Compensation” and the “Pay Versus Performance” sections in our 2023 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 2023 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, 2022:

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	132,253	—	1,023,229
Equity Compensation Plans Not Approved by Security Holders	—	—	—
Total	132,253	—	1,023,229

(a)    Includes the following as of December 31, 2022: (i) 60,489 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) 71,764 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 2023 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) 664,967 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) 294,327 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) 63,935 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 2023 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.

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 2023 Proxy Statement.

ALLETE, Inc. 2022 Form 10-K

59

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	67
	Consolidated Balance Sheet as of December 31, 2022 and 2021	69
	For the Years Ended December 31, 2022, 2021 and 2020
	Consolidated Statement of Income	70
	Consolidated Statement of Comprehensive Income	71
	Consolidated Statement of Cash Flows	72
	Consolidated Statement of Equity	73
	Notes to Consolidated Financial Statements	74
(2)	Financial Statement Schedules
	Schedule II – ALLETE Valuation and Qualifying Accounts and Reserves	126
	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
*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 Janet Lee (successor to Eva Waite and 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)
		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)

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60

Exhibit Number
		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
		Forty-third	August 1, 2022	1-3548 (Sept. 30, 2022, 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
		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).

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61

Exhibit Number
*4(e)	—	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).
*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).
*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. (filed as Exhibit 10(b)3 to the 2021 Form 10-K, File No. 1-3548).
*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 2018 (filed as Exhibit 10(a)1 to the March 31, 2018, Form 10-Q, File No. 1-3548).
*+10(e)3	—	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)4	—	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)5	—	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)6	—	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)7	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2022 (filed as Exhibit 10(e)9 to the 2021 Form 10-K, File No. 1-3548).
+10(e)8	—	ALLETE Executive Annual Incentive Plan Form of Award Effective 2023.
+10(e)9	—	ALLETE Executive Annual Incentive Plan Form of Award ALLETE Clean Energy Effective 2023.
*+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)3	—	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)4	—	ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2021 (filed as Exhibit 10(f)5 to the 2021 Form 10-K, File No. 1-3548).
*+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(h)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(h)2	—	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(h)3	—	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(h)4	—	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).

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62

Exhibit Number
*+10(h)5	—	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(h)6	—	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(h)7	—	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(h)8	—	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(h)9	—	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(h)10	—	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(h)11	—	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(h)12	—	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(h)14	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2022 (filed as Exhibit 10(i)17 to the 2021 Form 10-K, File No. 1-3548).
*+10(h)15	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2022 (filed as Exhibit 10(i)18 to the 2021 Form 10-K, File No. 1-3548).
+10(h)16	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2023.
+10(h)17	—	Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2023.
*+10(i)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(i)2	—	ALLETE Non-Employee Director Stock Plan (As Amended and Restated Effective May 10, 2022) (filed as Exhibit 99, File No. 333-265211).
*+10(j)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(j)4		ALLETE Non-Employee Director Compensation Summary effective January 1, 2022 (filed as Exhibit 10(k)4 to the 2021 Form 10-K, File No. 1-3548).
*+10(j)5		Amended and Restated ALLETE Non-Employee Director Stock Plan, effective May 10, 2022 (filed as Exhibit 99 to Form S-8, File No. 333-265211).
+10(j)6		ALLETE Non-Employee Director Compensation Summary effective January 1, 2023
*+10(k)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(k)2	—	Amendment to the Minnesota Power (now ALLETE) Director Compensation Deferral Plan, effective October 1, 2003 (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548).
*+10(k)3	—	Amendment to the ALLETE Director Compensation Deferral Plan, effective January 1, 2005 (filed as Exhibit 10(c) to the March 31, 2005, Form 10-Q, File No. 1-3548).
*+10(k)4	—	Amendment to the ALLETE Director Compensation Deferral Plan, effective October 1, 2006 (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548).
*+10(k)5	—	Amendment to the ALLETE Director Compensation Deferral Plan, effective July 24, 2012 (filed as Exhibit 10(n)5 to the 2012 Form 10-K, File No. 1-3548).
*+10(l)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(l)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(m)	—	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).
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.

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63

Exhibit Number
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, 2023, announcing earnings for the year ended December 31, 2022. (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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64

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, 2023	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, 2023
Bethany M. Owen	(Principal Executive Officer) and Director
/s/ Steven W. Morris	Senior Vice President and Chief Financial Officer	February 16, 2023
Steven W. Morris	(Principal Financial Officer and Principal Accounting Officer)

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65

Signatures (Continued)

Signature	Title	Date
/s/ George G. Goldfarb	Director	February 16, 2023
George G. Goldfarb
/s/ James J. Hoolihan	Director	February 16, 2023
James J. Hoolihan
/s/ Madeleine W. Ludlow	Director	February 16, 2023
Madeleine W. Ludlow
/s/ Charles R. Matthews	Director	February 16, 2023
Charles R. Matthews
/s/ Susan K. Nestegard	Director	February 16, 2023
Susan K. Nestegard
/s/ Douglas C. Neve	Director	February 16, 2023
Douglas C. Neve
/s/ Barbara A. Nick	Director	February 16, 2023
Barbara A. Nick
/s/ Robert P. Powers	Director	February 16, 2023
Robert P. Powers
/s/ Charlene A. Thomas	Director	February 16, 2023
Charlene A. Thomas

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66

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 sheet of ALLETE, Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, 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.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded New Energy from its assessment of internal control over financial reporting as of December 31, 2022, because it was acquired by the Company in a purchase business combination during 2022. We have also excluded New Energy from our audit of internal control over financial reporting. New Energy is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 1% and 5%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022.

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

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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.

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, 2022, there was $467 million of regulatory assets and $550 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, 2023

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

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CONSOLIDATED FINANCIAL STATEMENTS

ALLETE Consolidated Balance Sheet

As of December 31	2022	2021
Millions
Assets
Current Assets
Cash and Cash Equivalents	$36.4	$45.1
Accounts Receivable (Less Allowance of $1.6 and $1.8)	137.9	123.7
Inventories – Net	455.9	97.7
Prepayments and Other	87.8	24.8
Total Current Assets	718.0	291.3
Property, Plant and Equipment – Net	5,004.0	5,087.5
Regulatory Assets	441.0	511.8
Equity Investments	322.7	318.0
Goodwill and Intangible Assets – Net	155.6	0.8
Other Non-Current Assets	204.3	212.9
Total Assets	$6,845.6	$6,422.3
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable	$103.0	$111.0
Accrued Taxes	69.1	65.1
Accrued Interest	20.5	20.1
Long-Term Debt Due Within One Year	272.6	214.2
Other	251.0	133.0
Total Current Liabilities	716.2	543.4
Long-Term Debt	1,648.2	1,763.2
Deferred Income Taxes	158.1	181.8
Regulatory Liabilities	526.1	536.1
Defined Benefit Pension and Other Postretirement Benefit Plans	179.7	179.5
Other Non-Current Liabilities	269.0	280.8
Total Liabilities	3,497.3	3,484.8
Commitments, Guarantees and Contingencies (Note 9)
Equity
ALLETE Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 57.2 and 53.2 Shares Issued and Outstanding	1,781.5	1,536.7
Accumulated Other Comprehensive Loss	(24.4)	(23.8)
Retained Earnings	934.8	891.4
Total ALLETE Equity	2,691.9	2,404.3
Non-Controlling Interest in Subsidiaries	656.4	533.2
Total Equity	3,348.3	2,937.5
Total Liabilities and Equity	$6,845.6	$6,422.3

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Income

Year Ended December 31	2022	2021	2020
Millions Except Per Share Amounts
Operating Revenue
Contracts with Customers – Utility	$1,259.3	$1,227.9	$987.3
Contracts with Customers – Non-utility	303.8	179.9	170.5
Other – Non-utility	7.6	11.4	11.3
Total Operating Revenue	1,570.7	1,419.2	1,169.1
Operating Expenses
Fuel, Purchased Power and Gas – Utility	545.5	562.4	358.6
Transmission Services – Utility	76.7	75.3	67.0
Cost of Sales – Non-utility	182.8	68.8	66.7
Operating and Maintenance	318.9	259.2	252.0
Depreciation and Amortization	242.2	231.7	217.8
Taxes Other than Income Taxes	70.4	70.5	56.1
Impairment of Property, Plant and Equipment	—	—	12.7
Total Operating Expenses	1,436.5	1,267.9	1,030.9
Operating Income	134.2	151.3	138.2
Other Income (Expense)
Interest Expense	(75.2)	(69.1)	(65.6)
Equity Earnings	18.7	20.0	22.1
Other	22.4	8.7	14.7
Total Other Expense	(34.1)	(40.4)	(28.8)
Income Before Non-Controlling Interest and Income Taxes	100.1	110.9	109.4
Income Tax Benefit	(31.2)	(26.9)	(43.4)
Net Income	131.3	137.8	152.8
Net Loss Attributable to Non-Controlling Interest	(58.0)	(31.4)	(12.6)
Net Income Attributable to ALLETE	$189.3	$169.2	$165.4
Average Shares of Common Stock
Basic	55.9	52.4	51.9
Diluted	56.0	52.5	51.9
Basic Earnings Per Share of Common Stock	$3.38	$3.23	$3.18
Diluted Earnings Per Share of Common Stock	$3.38	$3.23	$3.18

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Comprehensive Income

Year Ended December 31	2022	2021	2020
Millions
Net Income	$131.3	$137.8	$152.8
Other Comprehensive Income (Loss)
Unrealized Gain (Loss) on Securities
Net of Income Tax (Benefit) Expense of $(0.2), $(0.1) and $0.1	(0.4)	(0.1)	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Tax (Benefit) Expense of $(0.1), $3.0 and $(3.1)	(0.2)	7.4	(7.6)
Total Other Comprehensive Income (Loss)	(0.6)	7.3	(7.5)
Total Comprehensive Income	130.7	145.1	145.3
Net Loss Attributable to Non-Controlling Interest	(58.0)	(31.4)	(12.6)
Total Comprehensive Income Attributable to ALLETE	$188.7	$176.5	$157.9

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Cash Flows

Year Ended December 31	2022	2021	2020
Millions
Operating Activities
Net Income	$131.3	$137.8	$152.8
Adjustments to Reconcile Net Income to Cash provided by Operating Activities:
AFUDC – Equity	(2.7)	(2.6)	(1.9)
Income from Equity Investments – Net of Dividends	2.4	2.2	(3.2)
(Gain) / Loss on Investments and Property, Plant and Equipment	1.2	(0.8)	(1.3)
Loss on Impairment of Assets	—	—	12.7
Depreciation Expense	242.0	231.6	217.7
Amortization of PSAs	(7.6)	(11.4)	(11.3)
Amortization of Other Intangible Assets and Other Assets	8.3	9.9	10.4
Deferred Income Tax Benefit	(38.5)	(26.9)	(43.4)
Share-Based and ESOP Compensation Expense	4.9	5.9	6.1
Defined Benefit Pension and Other Postretirement Benefit Expense	(3.0)	4.3	0.1
Bad Debt Expense	1.9	1.2	2.7
Payments for Tax Reform Refund	—	—	(0.2)
Fuel Adjustment Clause	15.1	(56.4)	5.0
Provision for Interim Rate Refund	18.4	—	—
Changes in Operating Assets and Liabilities
Accounts Receivable	(14.0)	(13.0)	(18.2)
Inventories	(256.1)	(23.5)	(1.4)
Prepayments and Other	(21.5)	(0.5)	0.9
Accounts Payable	(1.3)	15.0	11.8
Other Current Liabilities	116.2	28.0	11.7
Cash Contributions to Defined Benefit Pension Plans	—	(10.3)	(10.7)
Changes in Regulatory and Other Non-Current Assets	24.1	(12.0)	(31.0)
Changes in Regulatory and Other Non-Current Liabilities	0.2	(15.0)	(9.5)
Cash provided by Operating Activities	221.3	263.5	299.8
Investing Activities
Proceeds from Sale of Available-for-sale Securities	2.2	6.4	12.8
Payments for Purchase of Available-for-sale Securities	(2.4)	(3.6)	(8.7)
Acquisitions of Subsidiaries – Net of Cash and Restricted Cash Acquired	(155.0)	—	—
Payments for Equity Investments	(5.9)	(17.6)	(99.1)
Additions to Property, Plant and Equipment	(220.5)	(479.5)	(724.7)
Other Investing Activities	(2.4)	9.1	6.9
Cash used in Investing Activities	(384.0)	(485.2)	(812.8)
Financing Activities
Proceeds from Issuance of Common Stock	248.0	69.9	18.1
Equity Issuance Costs	(8.1)	—	—
Proceeds from Issuance of Short-Term and Long-Term Debt	785.4	733.0	672.4
Repayments of Short-Term and Long-Term Debt	(877.0)	(552.9)	(488.6)
Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs	155.7	90.9	414.5
Dividends on Common Stock	(145.9)	(131.9)	(128.2)
Other Financing Activities	(2.9)	(4.8)	(2.5)
Cash provided by Financing Activities	155.2	204.2	485.7
Change in Cash, Cash Equivalents and Restricted Cash	(7.5)	(17.5)	(27.3)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	47.7	65.2	92.5
Cash, Cash Equivalents and Restricted Cash at End of Period	$40.2	$47.7	$65.2

The accompanying notes are an integral part of these statements.

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ALLETE Consolidated Statement of Equity

	2022	2021	2020
Millions Except Per Share Amounts
Common Stock
Balance, Beginning of Period	$1,536.7	$1,460.9	$1,436.7
Common Stock Issued	244.8	75.8	24.2
Balance, End of Period	1,781.5	1,536.7	1,460.9
Accumulated Other Comprehensive Loss
Balance, Beginning of Period	(23.8)	(31.1)	(23.6)
Other Comprehensive Income – Net of Income Taxes
Unrealized Gain (Loss) on Debt Securities	(0.4)	(0.1)	0.1
Defined Benefit Pension and Other Postretirement Plans	(0.2)	7.4	(7.6)
Balance, End of Period	(24.4)	(23.8)	(31.1)
Retained Earnings
Balance, Beginning of Period	891.4	856.0	818.8
Net Income Attributable to ALLETE	189.3	169.2	165.4
Common Stock Dividends	(145.9)	(131.9)	(128.2)
Adjustment of Redeemable Non-Controlling Interest	—	(1.9)	—
Balance, End of Period	934.8	891.4	856.0
Non-Controlling Interest in Subsidiaries
Balance, Beginning of Period	533.2	505.6	103.7
Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs	182.9	90.9	414.5
Net Loss Attributable to Non-Controlling Interest	(58.0)	(31.4)	(12.6)
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities	—	(28.8)	—
Distributions to Non-Controlling Interest	(1.7)	(3.1)	—
Balance, End of Period	656.4	533.2	505.6
Total Equity	$3,348.3	$2,937.5	$2,791.4
Dividends Per Share of Common Stock	$2.60	$2.52	$2.47

The accompanying notes are an integral part of these statements.

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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. The presentation of certain prior period amounts on the Consolidated Financial Statements have been adjusted for comparative purposes.

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 two reportable segments: Regulated Operations and ALLETE Clean Energy. 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 14 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 1,200 MW of nameplate capacity wind energy generation with a majority contracted under PSAs of various durations. In addition, 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 Clean Energy currently has approximately 100 MW of wind energy facilities under contract to be sold to others.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

New Energy is a renewable energy development company with a primary focus on solar and storage facilities while also offering comprehensive operations, maintenance and asset management services.

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 2027 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, 2022, is approximately $7 million.

BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2022, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 9. Commitments, Guarantees and Contingencies.)

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, 2022, and 2021, 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 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 amount also includes 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	2022	2021	2020
Millions
Cash and Cash Equivalents	$36.4	$45.1	$44.3
Restricted Cash included in Prepayments and Other	1.5	0.3	0.8
Restricted Cash included in Other Non-Current Assets	2.3	2.3	20.1
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows	$40.2	$47.7	$65.2

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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	2022	2021	2020
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$72.8	$66.8	$62.0
Cash Paid (Received) for Income Taxes	$6.0	—	$(2.0)
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(9.6)	$(14.0)	$(67.0)
Reclassification of Property, Plant and Equipment to Inventory (a)	$99.7	—	—
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities (b)	—	$30.6	—
Capitalized Asset Retirement Costs	$11.8	$16.9	$4.1
AFUDC–Equity	$2.7	$2.6	$1.9

(a)The decommissioning of the existing Northern Wind assets resulted in a reclassification from Property, Plant and Equipment – Net to Inventories – Net in the second quarter of 2022 as they were repowered and subsequently sold to a subsidiary of Xcel Energy Inc. In the third quarter of 2022, safe harbor equipment was transferred to the project entity resulting in an additional reclassification from Property, Plant and Equipment – Net to Inventories – Net.

(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	2022	2021
Millions
Trade Accounts Receivable
Billed	$107.1	$100.6
Unbilled	29.2	24.7
Less: Allowance for Doubtful Accounts	1.6	1.8
Total Trade Accounts Receivable	134.7	123.5
Income Taxes Receivable	3.2	0.2
Total Accounts Receivable	$137.9	$123.7

Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to seven Large Power Customers. Receivables from these customers totaled $11.3 million as of December 31, 2022 ($7.8 million as of December 31, 2021). 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 2022, accounted for approximately 32 percent of Regulated Operations operating revenue and approximately 26 percent of consolidated operating revenue in 2022 (32 percent of Regulated Operations operating revenue and 28 percent of consolidated operating revenue in 2021 and 29 percent of Regulated Operations operating revenue and 25 percent of consolidated operating revenue in 2020).

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.

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Inventories – Net
As of December 31	2022	2021
Millions
Fuel (a)	$33.4	$18.7
Materials and Supplies	75.1	56.1
Construction of Wind Energy Facilities (b)	347.4	22.9
Total Inventories – Net	$455.9	$97.7

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

(b) Project costs related to ALLETE Clean Energy’s Northern Wind project sold in January 2023 and Red Barn wind project which is expected to be sold in the first half 2023. (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. The MPUC order for Minnesota Power’s 2015 IRP 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. Minnesota Power’s latest IRP, which was approved by the MPUC in an order dated January 9, 2023, includes ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. Boswell Unit 3 and Unit 4 have a net book value of approximately $235 million and $435 million, respectively, as of December 31, 2022. (See Note 4. Regulatory Matters.) Minnesota Power’s latest IRP also includes the retirement of Taconite Harbor. As of December 31, 2022, Taconite Harbor had a net book value of approximately $25 million. 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.

ALLETE, Inc. 2022 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 decline in energy prices or lower wind resource expectations could result in a future impairment.

In 2022 and 2021 there were triggering events that indicated an impairment for our property, plant, and equipment at certain ALLETE Clean Energy wind energy facilities with expiring PSAs for which a recoverability test was performed indicating that the undiscounted cash flows adequately supported the property, plant and equipment book values. As a result, no impairment was recorded in 2022 and 2021. In 2020, there were indicators of impairment for ALLETE Clean Energy’s Northern Wind project. See Immaterial Revision to Prior Period.

Immaterial Revision to Prior Period. We have identified an immaterial prior period error with respect to the recognition of a non-cash impairment expense for our Northern Wind operating assets in the fourth quarter of 2020 prior to the execution of the purchase and sales agreement for a repower and sale of the wind energy facility. Specifically, the remaining net book value of the property, plant and equipment used in the recoverability test was calculated incorrectly. If the net book value would have been calculated correctly in the recoverability test, an $8.8 million after-tax impairment expense would have been recognized in the fourth quarter of 2020. We evaluated the effects of this error on our previously-issued consolidated financial statements in accordance with the guidance in Accounting Standards Codification Topic (ASC) 250, Accounting Changes and Error Corrections, ASC 250-10-S99-1, Assessing Materiality, and ASC 250-10-S99-2, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, and concluded that no prior period is materially misstated. Accordingly, we have revised our consolidated financial statements for the impacted prior periods herein.

A summary of the effect of the revision on the Consolidated Statements of Income and Consolidated Statement of Comprehensive Income for the year ended December 31, 2020 is as follows:

Revision Impacts for the Year Ended December 31, 2020	As Reported	Adjustment	As Revised
Millions Except Per Share Amounts
Impairment of Property, Plant and Equipment	—	$12.7	$12.7
Income Tax Benefit	$(39.5)	(3.9)	(43.4)
Net Income Attributable to ALLETE	$174.2	$(8.8)	$165.4
Comprehensive Income Attributable to ALLETE	$166.7	$(8.8)	$157.9
Diluted Earnings Per Share	$3.35	$(0.17)	$3.18

ALLETE, Inc. 2022 Form 10-K

78

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

A summary of the effect of the revision on the Consolidated Balance Sheet as of December 31, 2021 is as follows:

Revision Impacts for the Year Ended December 31, 2021	As Reported	Adjustment	As Revised
Millions
Property, Plant and Equipment - Net	$5,100.2	$(12.7)	$5,087.5
Total Assets	$6,435.0	$(12.7)	$6,422.3
Deferred Income Taxes	$185.7	$(3.9)	$181.8
Total Liabilities	$3,488.7	$(3.9)	$3,484.8
Retained Earnings	$900.2	$(8.8)	$891.4
Total Equity	$2,946.3	$(8.8)	$2,937.5

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 13. Employee Stock and Incentive Plans.)

Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. Goodwill is assessed annually in the fourth quarter for impairment and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level.

As of the date of our annual goodwill impairment testing in 2022, the Company elected to bypass the qualitative assessment of goodwill for impairment, proceeding directly to the two-step impairment test for the New Energy reporting unit. In performing Step 1 of the impairment test, we compared the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the impairment test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

For Step 1 of the impairment test, we estimated the reporting unit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes a growth rate on debt-free cash flows. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. Our annual impairment test in 2022 indicated that the estimated fair value of New Energy exceeded its carrying value, and therefore no impairment existed. The fair value of the reporting unit was determined using a discounted cash flow model, using significant assumptions which included a discount rate of 14 percent, cash flow forecasts through 2027, industry average gross margins, and a terminal growth rate of 3.5 percent.

ALLETE, Inc. 2022 Form 10-K

79

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets
As of December 31	2022	2021
Millions
Contract Assets (a)	$21.0	$23.3
Operating Lease Right-of-use Assets	12.7	16.4
ALLETE Properties	19.1	19.4
Restricted Cash	2.3	2.3
Other Postretirement Benefit Plans	58.8	64.8
Other	90.4	86.7
Total Other Non-Current Assets	$204.3	$212.9

(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	2022	2021
Millions
Customer Deposits (a)	$150.7	$27.2
PSAs	6.1	12.6
Provision for Interim Rate Refund	18.4	—
Manufactured Gas Plant (b)	14.7	12.8
Fuel Adjustment Clause	—	5.0
Operating Lease Liabilities	3.2	4.8
Redeemable Non-Controlling Interest (c)	—	30.6
Other	57.9	40.0
Total Other Current Liabilities	$251.0	$133.0

(a)    Primarily related to deposits received by ALLETE Clean Energy for the Northern Wind project sold in January 2023 and the Red Barn wind project which is expected to be sold in the first half of 2023. (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 9. 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	2022	2021
Millions
Asset Retirement Obligation (a)	$200.4	$184.5
PSAs	26.9	39.5
Operating Lease Liabilities	9.3	11.6
Other	32.4	45.2
Total Other Non-Current Liabilities	$269.0	$280.8

(a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $32.4 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2022 ($28.5 million as of December 31, 2021).

ALLETE, Inc. 2022 Form 10-K

80

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	2022	2021
Millions
Operating Lease Cost	$6.3	$6.7
Other Information:
Operating Cash Flows From Operating Leases	$6.3	$6.7

Additional information related to leases was as follows:

As of December 31	2022		2021
Millions
Balance Sheet Information Related to Leases:
Other Non-Current Assets	$12.7		$16.4
Total Operating Lease Right-of-use Assets	$12.7		$16.4
Other Current Liabilities	$3.2		$4.8
Other Non-Current Liabilities	9.3		11.6
Total Operating Lease Liabilities	$12.5		$16.4
Weighted Average Remaining Lease Term (Years):
Operating Leases - Vehicles and Equipment	4		3
Operating Leases - Land and Other	16		27
Weighted Average Discount Rate:
Operating Leases - Vehicles and Equipment	3.9	%	3.8	%
Operating Leases - Land and Other	3.9	%	4.5	%

ALLETE, Inc. 2022 Form 10-K

81

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Maturities of lease liabilities were as follows:

	December 31, 2022
Millions
2023	$3.4
2024	3.1
2025	2.9
2026	2.9
2027	3.8
Thereafter	1.2
Total Lease Payments Due	17.3
Less: Imputed Interest	4.8
Total Lease Obligations	12.5
Less: Current Lease Obligations	3.2
Total Long-term Lease Obligations	$9.3

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 9. 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 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.

ALLETE, Inc. 2022 Form 10-K

82

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 14 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. One of these 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 expiring in 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 52 percent of total regulated utility kWh sales for the year ended December 31, 2022. Within industrial revenue, Minnesota Power had seven Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2022. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2026 through 2029. 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 $55 million per annum through 2026, $15 million in 2027, and $25 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.

ALLETE, Inc. 2022 Form 10-K

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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 2024 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.

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.

Sale of Renewable Development Projects includes revenue recognized from development only and development plus construction type projects that are sold to a customer. For development only projects, revenue is recognized at point in time when all required development responsibilities have been completed and ownership has transferred to the customer. For development plus construction, the transaction price is allocated to two performance obligations based upon the standalone selling price of each obligation. Revenue is recognized on the development performance obligation upon satisfying all required development activities and ownership transferring to the customer. Revenue for the construction performance obligation is recognized over time based on construction costs incurred, beginning at notice to proceed through the commercial operation date.

Other primarily includes revenue from BNI Energy unrelated to coal, revenue from New Energy for asset management services and non-development activities, 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.

ALLETE, Inc. 2022 Form 10-K

84

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, 2022, we have $21.0 million of assets recognized for costs incurred to obtain contracts with our customers ($23.3 million as of December 31, 2021). 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 $2.4 million of non-cash amortization for the year ended December 31, 2022 ($2.7 million for the year end December 31, 2021).

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 ownership percentage 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, 2022 and 2021, 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.

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.

ALLETE, Inc. 2022 Form 10-K

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NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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	2022	2021	2020
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credit (a)	$9.8	$6.1	$8.6
Interest and Investment Earnings	—	2.3	1.6
AFUDC - Equity	2.7	2.6	1.9
Gain on Land Sales	—	0.1	0.4
PSA Liability (b)	10.2	—	—
Other	(0.3)	(2.4)	2.2
Total Other Income (Expense) - Other	$22.4	$8.7	$14.7

(a)These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)

(b)The gain on removal of the PSA liability for the Northern Wind project upon decommissioning of the legacy wind energy facility assets, which was more than offset by a reserve for an anticipated loss on the sale of the Northern Wind project, was recorded in Cost of Sales - Non-Utility on the Consolidated Statement of Income.

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. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal credits related to public utility 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 11. 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.

ALLETE, Inc. 2022 Form 10-K

86

NOTE 2. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31	2022	2021
Millions
Regulated Operations
Property, Plant and Equipment in Service	$5,198.6	$5,028.7
Construction Work in Progress	74.0	108.7
Accumulated Depreciation	(1,972.3)	(1,834.6)
Regulated Operations – Net	3,300.3	3,302.8
ALLETE Clean Energy
Property, Plant and Equipment in Service	1,619.4	1,704.2
Construction Work in Progress	51.1	79.9
Accumulated Depreciation	(176.8)	(149.0)
ALLETE Clean Energy – Net	1,493.7	1,635.1
Corporate and Other (a)
Property, Plant and Equipment in Service	295.2	267.1
Construction Work in Progress	50.9	19.8
Accumulated Depreciation	(136.1)	(137.3)
Corporate and Other – Net	210.0	149.6
Property, Plant and Equipment – Net	$5,004.0	$5,087.5

(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	1 to 50	ALLETE Clean Energy	5 to 35
Transmission	50 to 75	Corporate and Other	3 to 50
Distribution	18 to 70

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.)

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NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)

Asset Retirement Obligations
Millions
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
Accretion	9.5
Liabilities Recognized	7.8
Liabilities Settled	(4.4)
Revisions in Estimated Cash Flows	3.0
Obligation as of December 31, 2022	$200.4

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.

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, 2022
Boswell Unit 4	$712.0	$340.1	$3.3	80
Transmission Assets	101.0	21.1	—	9.3 - 14.7
Total	$813.0	$361.2	$3.3
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

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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 $38.8 million in 2022 ($38.9 million in 2021; $29.9 million in 2020).

Minnesota Retail Rates. Minnesota Power’s retail rates through 2021 were based on a 2018 MPUC retail rate order that allowed 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.)

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. 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 are now 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.

At a hearing on January 23, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. Upon commencement of final rates, we expect additional revenue from base rates of approximately $60 million and an additional $10 million in revenue recognized under cost recovery riders on an annualized basis, subject to final written order and reconsideration. Final rates are expected to commence in the third quarter of 2023; interim rates will be collected through this period with reserves recorded as necessary. As a result of the MPUC’s determinations made on January 23, 2023, Minnesota Power has recorded a reserve for an interim rate refund of approximately $18 million pre-tax as of December 31, 2022, which is subject to MPUC approval of Minnesota Power’s refund calculation. In addition, Minnesota Power recorded a charge of approximately $8 million pre-tax to write-off the deferred portion of residential customer interim rates. Minnesota Power also recorded additional revenue of approximately $9 million pre-tax for an increase in expected recoveries under its cost recovery riders. Impacts of regulatory outcomes that are determined subsequent to the balance sheet date, and prior to issuance of the financial statements, are recognized in the financial statements as of the balance sheet date.

FERC-Approved Wholesale Rates. Minnesota Power has wholesale contracts with 14 non-affiliated municipal customers in Minnesota and SWL&P. Two 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 is effective through December 31, 2037. The wholesale electric service contract with SWL&P is effective through February 28, 2026. 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.

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NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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.

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 an MPUC order dated December 27, 2022, which provisionally approved Minnesota Power’s latest transmission factor filing submitted on October 31, 2022.

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 2020 order. On February 2, 2022, Minnesota Power submitted its latest renewable factor filing, which included a request to recover a regulatory asset of $3.8 million related to the recognition of production tax credits due to a metering error at Bison. The filing was approved in an order dated January 24, 2023 authorizing Minnesota Power to include updated billing rates on customer bills for recovery of the regulatory asset.

Solar Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place to charge retail customers on a current basis for solar costs related to investments and expenditures for meeting the state of Minnesota’s solar energy standard. Current customer billing rates for the solar cost recovery rider were approved by the MPUC in an order dated August 31, 2022.

Electric Vehicle Charging Infrastructure Petition. In April 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 October 2021 order, the MPUC approved Minnesota Power’s petition.

Fuel Adjustment Clause. In 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 through December 31, 2021. Minnesota Power submitted its annual true-up filing and a significant events filing in March 2022 requesting recovery of these under-collected fuel adjustment clause recoveries. The MPUC approved recovery of the regulatory asset in an order dated July 5, 2022; recovery of the regulatory asset will continue through mid-2023.

Minnesota Power also incurred higher fuel and purchased power costs in 2022 than those factored in its fuel adjustment forecast filed in May 2021 for 2022, which resulted in the recognition of an approximately $13 million regulatory asset as of December 31, 2022. Minnesota Power filed a significant events filing in June 2022 requesting to increase rates from August 2022 through December 2022 in order to recover the under-collected fuel adjustment clause recoveries that were expected for 2022. No parties objected to the request and higher rates were implemented in August 2022. Minnesota Power will request recovery of the remaining regulatory asset as part of its annual true-up filing expected to be submitted to the MPUC in March 2023.

In 2020, Minnesota Power filed its FAC report covering the period July 2018 through December 2019. In a 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, and refunded to customers in 2022.

Wisconsin Retail Rates. SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.4 percent and a 55.0 percent equity ratio.

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NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

2022 Wisconsin General Rate Case. In 2022, SWL&P filed a rate increase request with the PSCW seeking an average increase of 3.6 percent for retail customers. The filing sought an overall return on equity of 10.4 percent and a 55 percent equity ratio. On an annualized basis, the requested final rate increase would have generated an estimated $4.3 million in additional revenue. In an order dated December 20, 2022, the PSCW approved an annual increase of $3.3 million reflecting a return on equity of 10.0 percent and 55 percent equity ratio. Final rates went into effect January 1, 2023.

Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP, which was approved by the MPUC in an order dated January 9, 2023. The approved IRP, which reflects a joint agreement reached with various stakeholders, outlines Minnesota Power’s 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 up to 700 MW of new wind and solar energy resources, and ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. 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. Minnesota Power is expected to file its next IRP by March 1, 2025.

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, 2022, Minnesota Power submitted its 2021 consolidated filing detailing Minnesota Power’s CIP program results and proposed CIP financial incentive, which was approved by the MPUC in an order dated July 5, 2022. As a result, Minnesota Power recognized revenue of $1.9 million in 2022 for the approved CIP financial incentive ($2.4 million in 2021 and $2.4 million in 2020). CIP financial incentives are recognized in the period in which the MPUC approves the filing.

In 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 goal is $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 which is subject to various outstanding legal challenges related to the return on equity calculation and refund period ordered by the FERC. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the 2020 FERC order back to the FERC. We cannot predict the return on equity the FERC will ultimately authorize in the remanded proceeding. (See Note 6. Equity Investments.)

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 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 commenced in 2022 with a portion of these projects placed into service in the fourth quarter of 2022; the remaining project is expected to be placed into service in 2023.

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.

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NOTE 4. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
As of December 31	2022	2021
Millions
Current Regulatory Assets (a)
Fuel Adjustment Clause (b)	$25.6	—
Total Current Regulatory Assets	$25.6	—
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (c)	$225.9	$226.4
Income Taxes (d)	97.6	104.7
Cost Recovery Riders (e)	41.2	63.2
Asset Retirement Obligations (f)	35.6	33.1
Manufactured Gas Plant (g)	15.1	17.0
Fuel Adjustment Clause (b)	14.5	56.4
PPACA Income Tax Deferral	4.1	4.3
Other	7.0	6.7
Total Non-Current Regulatory Assets	$441.0	$511.8
Current Regulatory Liabilities (h)
Provision for Interim Rate Refund	$18.4	—
Fuel Adjustment Clause (b)	—	$5.0
Transmission Formula Rates	4.9	3.1
Other	0.1	0.5
Total Current Regulatory Liabilities	$23.4	$8.6
Non-Current Regulatory Liabilities
Income Taxes (d)	$332.5	$353.4
Wholesale and Retail Contra AFUDC (j)	80.7	83.7
Plant Removal Obligations (k)	60.0	52.6
Defined Benefit Pension and Other Postretirement Benefit Plans (c)	17.6	28.1
North Dakota Investment Tax Credits (l)	16.9	12.2
Boswell Units 1 and 2 Net Plant and Equipment (i)	6.7	0.4
Non-Jurisdictional Land Sales (m)	7.5	—
Other	4.2	5.7
Total Non-Current Regulatory Liabilities	$526.1	$536.1

(a)Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.

(b)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.)

(c)Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, 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 12. Pension and Other Postretirement Benefit Plans.)

(d)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.

(e)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 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, 2022, will be recovered within the next two years.

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

(g)This 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.

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

(i)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.

(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.

(m)This regulatory liability represents the net proceeds from the sale of certain land by Minnesota Power that is expected to be refunded to ratepayers through a future rate case or through its renewable resources rider.

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NOTE 5. ACQUISITIONS

2022 Activity

New Energy. On April 15, 2022, a wholly-owned subsidiary of ALLETE acquired 100 percent of the membership interests of New Energy for a purchase price of $165.5 million. Total consideration of approximately $158.8 million was paid in cash on the acquisition date, which is net of cash acquired and debt assumed. New Energy, which is headquartered in Annapolis, Maryland, is a renewable energy development company with a primary focus on solar and storage facilities while also offering comprehensive operations, maintenance and asset management services. The acquisition of New Energy is consistent with ALLETE’s stated strategy of additional investment in renewable energy and related infrastructure across North America to support the Company’s sustainability-in-action strategy while providing potential long-term earnings growth.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price, which was finalized in the fourth quarter of 2022, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis. The goodwill recorded is primarily attributable to the highly skilled workforce of New Energy and synergies expected to arise as a result of the acquisition.

Since the acquisition in April 2022, aggregate revenue was $80.2 million. The Company has not presented separate results of operations since closing or combined pro forma financial information of the Company and New Energy since the beginning of 2021, as the results of operations for New Energy are not material to the Company's consolidated financials.

Millions
Assets Acquired
Cash and Cash Equivalents	$3.9
Accounts Receivable	1.4
Inventory (a)	25.3
Other Current Assets	12.8
Property, Plant and Equipment - Net	16.4
Goodwill (b)	154.9
Other Non-Current Assets	2.1
Total Assets Acquired	$216.8
Liabilities Assumed
Current Liabilities	$23.6
Long-Term Debt Due Within One Year	28.3
Long-Term Debt	5.9
Other Non-Current Liabilities	0.2
Total Liabilities Assumed	$58.0
Net Identifiable Assets Acquired	$158.8

(a)Includes $11.6 million of purchase price accounting for certain projects under development at the time of acquisition.

(b)For tax purpose, the purchase price allocation resulted in $154.9 million of deductible goodwill.

Acquisition-related costs were $2.7 million after-tax, expensed as incurred during 2022 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

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NOTE 6. 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, 2023, we invested an additional $0.8 million in ATC. In total, we expect to invest approximately $8.2 million in 2023.

ALLETE’s Investment in ATC
Year Ended December 31	2022	2021
Millions
Equity Investment Beginning Balance	$154.5	$149.0
Cash Investments	5.9	—
Equity in ATC Earnings	19.3	21.3
Distributed ATC Earnings	(15.5)	(17.2)
Amortization of the Remeasurement of Deferred Income Taxes	1.2	1.4
Equity Investment Ending Balance	$165.4	$154.5

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2022	2021
Millions
Current Assets	$89.6	$89.8
Non-Current Assets	5,997.8	5,628.1
Total Assets	$6,087.4	$5,717.9
Current Liabilities	$511.9	$436.9
Long-Term Debt	2,613.0	2,513.0
Other Non-Current Liabilities	485.8	422.0
Members’ Equity	2,476.7	2,346.0
Total Liabilities and Members’ Equity	$6,087.4	$5,717.9

Income Statement Data
Year Ended December 31	2022	2021	2020
Millions
Revenue	$751.2	$754.8	$758.1
Operating Expense	381.5	376.2	372.4
Other Expense	122.9	113.9	110.9
Net Income	$246.8	$264.7	$274.8
ALLETE’s Equity in Net Income	$19.3	$21.3	$22.3

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 which is subject to various outstanding legal challenges related to the return on equity calculation and refund period ordered by the FERC. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the 2020 FERC order back to FERC. As a result of this decision, ATC recorded a reserve in the third quarter of 2022 for anticipated refunds to its customers for approximately $31 million of which our share was approximately $2.4 million pre-tax. We cannot predict the return on equity FERC will ultimately authorize in the remanded proceeding.

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.

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NOTE 6. 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, 2021	$163.5
Equity in Nobles 2 Earnings (a)	(0.6)
Distributed Nobles 2 Earnings	(5.6)
Equity Investment Balance as of December 31, 2022	$157.3

(a)The Company also recorded net loss attributable to non-controlling interest of $10.6 million related to its investment in Nobles 2.

NOTE 7. 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.

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NOTE 7. 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, 2022, and December 31, 2021. 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, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities	$7.7	—	—	$7.7
Available-for-sale – Corporate and Governmental Debt Securities (b)	—	$5.7	—	5.7
Cash Equivalents	4.2	—	—	4.2
Total Fair Value of Assets	$11.9	$5.7	—	$17.6
Liabilities:
Deferred Compensation (c)	—	$15.0	—	$15.0
Total Fair Value of Liabilities	—	$15.0	—	$15.0

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

(b)As of December 31, 2022, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $2.7 million, in three years to less than five years was $1.9 million and in five or more years was $0.4 million.

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

	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	—	$6.2	—	6.2
Cash Equivalents	2.5	—	—	2.5
Total Fair Value of Assets	$11.4	$6.2	—	$17.6
Liabilities: (b)
Deferred Compensation	—	$18.0	—	$18.0
Total Fair Value of Liabilities	—	$18.0	—	$18.0

(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, 2022 and 2021, 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. 2022 Form 10-K

96

NOTE 7. FAIR VALUE (Continued)

Financial Instruments	Carrying Amount	Fair Value
Millions
Short-Term and Long-Term Debt (a)
December 31, 2022	$1,929.1	$1,782.7
December 31, 2021	$1,986.4	$2,192.6

(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 $322.7 million as of December 31, 2022 ($318.0 million as of December 31, 2021). 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, 2022 and 2021, there were no indicators of impairment. (See Note 6. Equity Investments.)

Goodwill. The Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. The Company’s goodwill is a result of the New Energy acquisition in 2022. (See Note 1. Operations and Significant Accounting Policies and Note 5. Acquisitions.) The aggregate carrying amount of goodwill was $154.9 million as of December 31, 2022.

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, 2022, and 2021, 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. The MPUC order for Minnesota Power’s 2015 IRP 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. Minnesota Power’s latest IRP, which was approved by the MPUC in an order dated January 9, 2023, includes ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. Boswell Unit 3 and Unit 4 have a net book value of approximately $235 million and $435 million, respectively, as of December 31, 2022. (See Note 4. Regulatory Matters.) Minnesota Power’s latest IRP also includes the retirement of Taconite Harbor. As of December 31, 2022, Taconite Harbor had a net book value of approximately $25 million. 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 8. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2022, total short-term debt outstanding was $272.6 million ($214.2 million as of December 31, 2021), and consisted of long-term debt due within one year and included $0.1 million of unamortized debt issuance costs.

As of December 31, 2022, we had consolidated bank lines of credit aggregating $475.7 million ($432.0 million as of December 31, 2021), most of which expire in January 2026. We had $32.8 million outstanding in standby letters of credit and $31.3 million outstanding draws under our lines of credit as of December 31, 2022 ($31.5 million in standby letters of credit and $159.7 million outstanding draws as of December 31, 2021).

ALLETE, Inc. 2022 Form 10-K

97

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt. As of December 31, 2022, total long-term debt outstanding was $1,648.2 million ($1,763.2 million as of December 31, 2021) and included $8.2 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2023 is $91.9 million; $94.8 million in 2024; $386.1 million in 2025; $79.4 million in 2026; $122.5 million in 2027; and $1,154.4 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 February 28, 2022, ALLETE entered into an unsecured term loan agreement (February Term Loan) to borrow up to $175 million. No draws were made on the February Term Loan, which was subsequently terminated in April 2022.

On March 24, 2022, ALLETE entered into a $170 million unsecured term loan agreement (March Term Loan). The Term Loan is due March 23, 2023, and may be repaid at any time. Interest is payable monthly at a rate per annum equal to SOFR plus 0.75 percent. Proceeds from the Term Loan were used for general corporate purposes.

On August 9, 2022, ALLETE issued $75 million of its First Mortgage Bonds (Bonds) to certain institutional buyers in the private placement market. The Bonds, which bear interest at 4.54 percent, will mature in August 2032 and pay interest semi-annually in February and August of each year, commencing on February 9, 2023. 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 refinance existing indebtedness 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.

ALLETE, Inc. 2022 Form 10-K

98

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt (Continued)

Long-Term Debt
As of December 31	2022	2021
Millions
First Mortgage Bonds
3.40% Series Due 2022	—	$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	100.0
4.54% Series Due 2032	75.0	—
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
Armenia Mountain Senior Secured Notes 3.26% Due 2024	19.3	29.1
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8	27.8
Revolving Credit Facility Variable Rate Due 2026	13.0	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 2022	—	110.0
Unsecured Term Loan Variable Rate Due 2023	170.0	—
Other Long-Term Debt, 2022 Weighted Average Rate 4.94% Due 2024 – 2051	82.0	57.5
Unamortized Debt Issuance Costs	(8.3)	(9.0)
Total Long-Term Debt	1,920.8	1,977.4
Less: Due Within One Year	272.6	214.2
Net Long-Term Debt	$1,648.2	$1,763.2

ALLETE, Inc. 2022 Form 10-K

99

NOTE 8. 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, 2022, our ratio was approximately 0.40 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, 2022, ALLETE was in compliance with its financial covenants.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The following table details the estimated minimum payments for certain long-term commitments as of December 31, 2022:

	2023	2024	2025	2026	2027	Thereafter
Millions
Capital Purchase Obligations	$26.6	$10.6	$1.3	$2.7	—	$0.6
Easements (a)	$7.8	$7.9	$8.0	$8.1	$8.2	$206.9
PPAs (b)	$151.3	$145.8	$137.0	$136.9	$123.6	$1,010.3
Other Purchase Obligations (c)	$49.9	$10.2	$6.5	—	—	—

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

(b)Does not include 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, 2022, Square Butte had total debt outstanding of $210.2 million. Annual debt service for Square Butte is expected to be approximately $47.2 million in 2023, $32.2 million in 2024, $28.4 million in 2025, and $28.6 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.

ALLETE, Inc. 2022 Form 10-K

100

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power’s cost of power purchased from Square Butte during 2022 was $82.7 million ($82.4 million in 2021; $79.5 million in 2020). 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 $5.1 million in 2022 ($5.8 million in 2021; $7.1 million in 2020). 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, 2022:

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

(a)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.

(b)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, 2022:

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 32 percent in 2022 (28 percent in 2021 and in 2020). (See Square Butte PPA.)

(c)Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power.

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

ALLETE, Inc. 2022 Form 10-K

101

NOTE 9. 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 2023. 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 in March 2021 revising 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. Minnesota Power will continue to monitor ongoing CSAPR rulemakings and compliance implementation, including the EPA’s Good Neighbor Rule proposed on April 6, 2022, to modify certain aspects of the CSAPR’s program scope and extent.

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. In June 2021, the EPA announced it will reconsider the December 2020 final rule retaining the 2012 particulate matter NAAQS. On January 6, 2023 the EPA announced a proposed rule to revise the primary annual particulate matter NAAQS from its current level while retaining the other primary and secondary particulate matter NAAQS. A final rule is expected by the end of 2023. The EPA also announced in October 2021 that it was reconsidering the 2020 Ozone NAAQS rule finalized in December 2020, and issued a policy assessment on April 28, 2022, recommending retention of the current standard. A proposed Ozone NAAQS rule is expected in the first half of 2023. Anticipated compliance costs related to the proposed and expected NAAQS revisions cannot yet be estimated; however, costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

ALLETE, Inc. 2022 Form 10-K

102

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA Good Neighbor Plan for 2015 Ozone NAAQS. On April 6, 2022, the EPA published a proposed rule, the Good Neighbor Plan, to address regional ozone transport for the 2015 Ozone NAAQS by reducing NOx emissions during the period of May 1 through September 30 (ozone season). This rule is intended to address certain good neighbor or interstate transport provisions of the Clean Air Act relative to the 2015 Ozone NAAQS. In the justification for the proposed rule, the EPA asserted that 26 states, including Minnesota, are modeled as significant contributors to downwind states’ challenges in attaining or maintaining ozone NAAQS compliance within their state borders. The Good Neighbor Plan proposes to resolve this interstate transport issue by implementing a variety of NOx reduction strategies, including federal implementation plan requirements, NOx emission limitations, and ozone season allowance program requirements, beginning with the 2023 ozone season. The proposed rule would apply to fossil-fuel fired power plants in 25 states and certain other industrial sources in 23 states. Implementation of the rule would occur in part through changes to the existing CSAPR program.

Minnesota Power reviewed the proposed rule, assessed its potential impacts and submitted public comments to the EPA on June 21, 2022. Concerns noted by Minnesota Power and other entities included the technical accuracy of the EPA’s assumptions and methods used to identify Minnesota as a significant contributor state, as well as the proposed rule’s intended timeline. Anticipated compliance costs related to the Good Neighbor Plan cannot yet be estimated; however, the costs could be material, including costs of additional NOx controls, emission allowance program participation, or operational changes, if any are required. Minnesota Power would seek recovery of additional costs through a rate proceeding. The EPA intends to issue a final rule in early 2023, following a final action to approve or disapprove the ozone transport State Implementation Plans (SIPs). On January 31, 2023, the EPA announced its final action to partially disapprove SIPs for the states of Minnesota and Wisconsin, and to disapprove 19 other SIP submissions. The Company is currently reviewing this SIP final action and any associated costs cannot yet be anticipated until the issuance of the EPA’s final Good Neighbor Plan, which is expected in March 2023.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters (Industrial Boiler MACT) Rule. A final rule issued by the EPA for Industrial Boiler MACT became effective in 2013 with compliance required at major existing sources in 2016. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. Compliance with the Industrial Boiler MACT Rule consisted largely of adjustments to fuels and operating practices and compliance costs were not material. Subsequent to this initial rulemaking, litigation from 2016 through 2018 resulted in court orders directing that the EPA reconsider certain aspects of the regulation including the basis for and numerical value of several different emission limits. On October 6, 2022, the EPA published a final rule in the Federal Register incorporating these changes. The rule became effective on December 5, 2022, imposing a 3-year compliance deadline of October 6, 2025. Minnesota Power’s initial review of this new rule indicates that the revisions should not significantly impact the Company’s affected units. As such, compliance costs associated with the new Industrial Boiler MACT Rule are not currently expected to be material; however Minnesota Power would seek recovery of additional costs through a rate proceeding.

Climate Change. The scientific community generally accepts that emissions of GHGs 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; increased risk of wildfires; 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.

ALLETE, Inc. 2022 Form 10-K

103

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 from 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, Hibbard Units 3 and 4, and Taconite Harbor Units 1 and 2; Taconite Harbor Units 1 and 2 are currently economically idled.

In January 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 for review of the D.C. Circuit’s opinion were subsequently granted by the U.S. Supreme Court in October 2021, consolidated under West Virginia v. EPA et al. On June 30, 2022, the U.S. Supreme Court released its opinion in favor of West Virginia and aligned parties. The Supreme Court found the EPA’s CPP structure of generation shifting to be disallowed under Section 111(d) of the CCA on grounds of the major questions doctrine. The court did not opine upon the regulatory approach the EPA proposed in the Affordable Clean Energy Rule. The petitions were remanded to the D.C. Circuit. The EPA has indicated that it intends to issue a proposed rule in early 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.

In April 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.

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.

Additionally in January 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. Currently, the EPA is a performing a comprehensive review of the Section 111(b) GHG NSPS for electric generating units, with a notice of proposed rulemaking expected in early 2023. Minnesota Power is monitoring the NSPS final rule and any further Section 111(b) developments including their potential impact to the Company. The proposed combined-cycle natural gas-fired generating facility, NTEC, is expected to meet these NSPS requirements.

ALLETE, Inc. 2022 Form 10-K

104

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 (BATW) 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 its 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 2023.

Under the 2020 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 will either need to be re-used in a closed-loop process or routed to a FGD scrubber. FGD wastewater is required to meet stringent water quality standards for discharge to surface water.

Bottom ash transport and FGD wastewater ELG’s are not currently expected to have a significant impact on Minnesota Power operations. Boswell Energy Center, where ELG’s are primarily applicable, completed conversion to dry bottom ash handling and installed a FGD dewatering system in September 2022. The dry conversion projects eliminated bottom ash transport water and minimized wastewater from the FGD system. Re-use and onsite consumption is planned for the remaining FGD waste stream and for dewatering legacy wastewater from Boswell’s existing impoundments. Water re-use and consumption activities are expected to eliminate the need for surface water discharges prior to the current ELG Rule deadline of December 31, 2025.

The EPA’s additional reconsideration of legacy wastewater and leachate discharge requirements has the potential to impact leachate discharges associated with the closed impoundment at the Laskin and Taconite Harbor Energy Centers Dry Ash Landfill. In its spring 2022 Unified Agenda, the EPA announced it intends to consolidate consideration of legacy wastewater and leachate with the ELG/FGD and BATW proposed rulemaking currently expected in 2023. It is unknown at this time if the rule revisions will include new requirements for these waste streams.

At this time, we estimate no additional material compliance costs for ELG bottom ash water and FGD requirements. Compliance costs we might incur related to other ELG waste streams (e.g., leachate) or other potential future water discharge regulations at Minnesota Power facilities 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.

ALLETE, Inc. 2022 Form 10-K

105

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 transmitted a final list of 32 EPA-added wild rice waters to the MPCA in November 2021. This list 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 (2015 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. Minnesota Power sought EPA approval under the Part A Rule to extend the closure date for two active Boswell impoundments in November 2020. Upon completion of dry ash conversion activities, Boswell ceased disposal in both impoundments on September 17, 2022 and formally withdrew the CCR Part A Application. The EPA acknowledged the Part A variance application withdrawal on September 20, 2022, and indicated that no further EPA review of Boswell’s Part A variance application will occur. Both impoundments are now inactive and have initiated closure.

Additionally, the EPA released a proposed Part B rulemaking in February 2020 addressing 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 updated fall 2022 regulatory agenda, finalization of the remainder of the proposed Part B Rule is expected in late 2023. Two additional rulemakings are also expected in mid-2023, the proposed Legacy Impoundment Rule and the Final Federal Permit Rule. The Legacy Impoundment Rule will include a revised definition for legacy CCR Impoundments which could regulate impoundments that had closed prior to the effective date of the 2015 Rule. The Final Federal Permit Rule will finalize procedures for implementing a CCR Federal Permit Program. Expected compliance costs at Boswell due to the 2018 court decision and subsequent rule revisions are reflected in our estimate of compliance costs for the CCR rule noted previously.

ALLETE, Inc. 2022 Form 10-K

106

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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, 2022, we have recorded a liability of $14.9 million for remediation costs at this site. SWL&P has recorded the site as an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. The majority of 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, 2022, we had $290.3 million of outstanding letters of credit issued, including those issued under our revolving credit facility.

Regulated Operations. As of December 31, 2022, we had $28.2 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 is party to PSAs that expire in various years between 2024 and 2039. As of December 31, 2022, ALLETE Clean Energy has $222.3 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, 2022, BNI Energy had surety bonds outstanding of $82.4 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 $82.1 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, 2022, ALLETE South Wind has $11.7 million outstanding in standby letters of credit, related to our portion of the security requirements relative to our ownership in Nobles 2.

New Energy. As of December 31, 2022, New Energy had $4.2 million outstanding in standby letters of credit pledged as security in connection with the acquisition of solar equipment for projects under development. New Energy does not believe it is likely that any of these outstanding letters of credit will be drawn upon.

South Shore Energy. As of December 31, 2022, 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, 2022, 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.

ALLETE, Inc. 2022 Form 10-K

107

NOTE 9. 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, 2022, we owned 42 percent of the assessable land in the Town Center District (30 percent as of December 31, 2021). As of December 31, 2022, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $1.3 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.

NOTE 10. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2019	51,679	$1,436.7
Employee Stock Purchase Plan	13	0.7
Invest Direct	309	18.3
Share-Based Compensation	84	5.2
Balance as of December 31, 2020	52,085	1,460.9
Employee Stock Purchase Plan	17	0.8
Invest Direct	263	17.5
Share-Based Compensation	73	6.5
Equity Issuance Program	782	51.0
Balance as of December 31, 2021	53,220	1,536.7
Employee Stock Purchase Plan	11	0.9
Invest Direct	244	14.9
Share-Based Compensation	82	5.3
Equity Issuance	3,680	223.7
Balance as of December 31, 2022	57,237	$1,781.5

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, 2022. For the year ended December 31, 2022, no shares of common stock were issued under this agreement (0.8 million shares for net proceeds of $51.0 million in 2021; none in 2020) .

On April 5, 2022, ALLETE issued and sold approximately 3.7 million shares of ALLETE common stock. Net proceeds of approximately $224 million were received from the sale of shares. Proceeds were used primarily to fund the acquisition of New Energy and capital investments at ALLETE Clean Energy.

ALLETE, Inc. 2022 Form 10-K

108

NOTE 10. COMMON STOCK AND EARNINGS PER SHARE (Continued)

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
2022
Net Income Attributable to ALLETE	$189.3		$189.3
Average Common Shares	55.9	0.1	56.0
Earnings Per Share	$3.38		$3.38
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	$165.4		$165.4
Average Common Shares	51.9	—	51.9
Earnings Per Share	$3.18		$3.18

NOTE 11. INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31	2022	2021	2020
Millions
Current Income Tax Expense (a)
Federal	$1.2	—	—
State	6.1	—	—
Total Current Income Tax Expense	$7.3	—	—
Deferred Income Tax Expense (Benefit)
Federal (b)	$(32.8)	$(37.2)	$(51.5)
State (c)	(5.2)	10.8	8.6
Investment Tax Credit Amortization	(0.5)	(0.5)	(0.5)
Total Deferred Income Tax Expense (Benefit)	$(38.5)	$(26.9)	$(43.4)
Total Income Tax Expense (Benefit)	$(31.2)	$(26.9)	$(43.4)

(a)For the years ended December 31, 2021 and 2020, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of certain tax legislation. Federal and state NOLs are being carried forward to offset current and future taxable income. For the year ended December 31, 2022, federal NOLs were fully utilized and production tax credits were used to partially offset federal taxable income.

(b)For the years ended December 31, 2022, 2021 and 2020, the federal tax benefit is primarily due to production tax credits.

(c)For the year ended December 31, 2022, the state impact includes the benefit of deferred repricing as a result of the New Energy acquisition.

ALLETE, Inc. 2022 Form 10-K

109

NOTE 11. INCOME TAX EXPENSE (Continued)

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2022		2021		2020
Millions
Income Before Non-Controlling Interest and Income Taxes	$100.1		$110.9		$109.4
Statutory Federal Income Tax Rate	21	%	21	%	21	%
Income Taxes Computed at Statutory Federal Rate	$21.0		$23.3		$23.0
Increase (Decrease) in Tax Due to:
State Income Taxes	8.6		8.6		6.5
Deferred Income Tax Revaluation	(7.9)		—		—
Production Tax Credits	(50.7)		(53.5)		(62.7)
Investment Tax Credits	(4.1)		—		—
Regulatory Differences – Excess Deferred Tax Benefit (a)	(9.1)		(9.5)		(9.9)
Non-Controlling Interest	11.2		6.3		2.7
AFUDC - Equity	(1.1)		(1.0)		(0.8)
Other	0.9		(1.1)		(2.2)
Total Income Tax Benefit	$(31.2)		$(26.9)		$(43.4)

(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 31.2 percent for 2022 (benefit of 24.3 percent for 2021; benefit of 39.7 percent for 2020). The 2022 and 2021 effective tax rates were primarily impacted by production tax credits and non-controlling interests in subsidiaries. The 2020 effective tax rate was primarily impacted by production tax credits.

Deferred Income Tax Assets and Liabilities
As of December 31	2022	2021
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation	$46.4	$44.5
Property-Related	61.9	54.8
NOL Carryforwards	16.7	67.5
Capital Loss Carryforwards	13.1	—
Tax Credit Carryforwards	548.7	509.1
Power Sales Agreements	13.7	16.5
Regulatory Liabilities	95.5	101.5
Other	28.1	18.0
Gross Deferred Income Tax Assets	824.1	811.9
Deferred Income Tax Asset Valuation Allowance	(60.2)	(69.0)
Total Deferred Income Tax Assets	$763.9	$742.9
Deferred Income Tax Liabilities
Deferred Gain	$7.9	$7.9
Property-Related	661.7	680.8
Regulatory Asset for Benefit Obligations	57.7	54.9
Unamortized Investment Tax Credits	30.0	30.5
Partnership Basis Differences	126.0	106.3
Fuel Adjustment Clause	10.7	14.3
Regulatory Assets	28.0	30.0
Total Deferred Income Tax Liabilities	$922.0	$924.7
Net Deferred Income Taxes (a)	$158.1	$181.8

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

ALLETE, Inc. 2022 Form 10-K

110

NOTE 11. INCOME TAX EXPENSE (Continued)

NOL and Tax Credit Carryforwards
As of December 31	2022	2021
Millions
Federal NOL Carryforwards (a)	—	$177.3
Federal Tax Credit Carryforwards	$464.5	$416.4
Federal Capital Loss (a)	$35.1	—
State NOL Carryforwards (a)	$323.0	$506.9
State Tax Credit Carryforwards (b)	$24.5	$24.2
State Capital Loss (a)	$83.2	—

(a)Pre-tax amounts.

(b)Net of a $59.6 million valuation allowance as of December 31, 2022 ($68.6 million as of December 31, 2021).

The federal NOL, capital loss and tax credit carryforward periods expire between 2026 and 2043. We expect to fully utilize the federal NOL, capital loss and tax credit carryforwards; therefore, no federal valuation allowance has been recognized as of December 31, 2022. The pre-apportioned state NOL, capital loss and tax credit carryforward periods expire between 2023 and 2046. We have established a valuation allowance against certain state NOL, capital loss and tax credits that we do not expect to utilize before their expiration.

Gross Unrecognized Income Tax Benefits	2022	2021	2020
Millions
Balance at January 1	$1.3	$1.4	$1.4
Additions for Tax Positions Related to the Current Year	—	—	0.1
Reductions for Tax Positions Related to Prior Years	—	(0.1)	(0.1)
Balance as of December 31	$1.3	$1.3	$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, 2022, included $0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2022, we had immaterial accrued interest (none as of December 31, 2021, and 2020) 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 2022, 2021 and 2020. There were no penalties recognized in 2022, 2021 or 2020. The unrecognized tax benefit amounts have been presented as an increase to the net deferred tax liability 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 is currently under examination by the state of Wisconsin for the tax years 2018 through 2020. ALLETE has no open federal audits, and is no longer subject to federal examination for years before 2019 or state examination for years before 2018. Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns.

ALLETE, Inc. 2022 Form 10-K

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NOTE 12. 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 2016. The plans provide defined benefits based on years of service and final average pay. We made no contributions to the plan trusts in 2022 ($10.3 million in 2021; $10.7 million in 2020). We also have a defined contribution RSOP covering substantially all employees. The 2022 plan year employer contributions totaled $12.0 million ($11.5 million for the 2021 plan year; $11.2 million for the 2020 plan year). (See Note 10. Common Stock and Earnings Per Share and Note 13. 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 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 2015, and in 2018, the postretirement life plan was amended to limit the benefit level for union employees retiring after December 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 2022, no contributions were made to the VEBAs (none in 2021; none in 2020) and no contributions were made to the grantor trusts (none in 2021; none in 2020).

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. On January 17, 2023, we contributed $6.5 million in cash to the defined benefit pension plans. We do not expect to make any further contributions to the defined benefit pension plans in 2023, and we do not expect to make any contributions to the defined benefit postretirement health and life plans in 2023.

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. 2022 Form 10-K

112

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
As of December 31	2022	2021
Millions
Accumulated Benefit Obligation	$724.5	$875.5
Change in Benefit Obligation
Obligation, Beginning of Year	$911.7	$965.7
Service Cost	9.3	11.0
Interest Cost	27.2	24.6
Plan Amendments	0.8	—
Plan Curtailments	—	(1.4)
Actuarial Gain (a)	(160.6)	(39.0)
Benefits Paid	(58.9)	(56.5)
Participant Contributions	10.2	7.3
Obligation, End of Year	$739.7	$911.7
Change in Plan Assets
Fair Value, Beginning of Year	$745.7	$759.4
Actual Return on Plan Assets	(130.5)	23.1
Employer Contribution (b)	12.3	19.7
Benefits Paid	(58.9)	(56.5)
Fair Value, End of Year	$568.6	$745.7
Funded Status, End of Year	$(171.1)	$(166.0)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(2.1)	$(2.1)
Non-Current Liabilities (c)	$(169.0)	$(163.9)

(a)    Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

(b)    Includes Participant Contributions noted above, any contributions made by the Company to pension plan trusts and any direct benefit payments made under certain plans.

(c)    Presented here net of amounts related to prepaid pension for SWL&P that are reclassified to Regulatory Assets on the Consolidated Balance Sheet.

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 $0.1 million as of December 31, 2022 (net loss of $260.2 million and prior service credit of $1.0 million as of December 31, 2021).

ALLETE, Inc. 2022 Form 10-K

113

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2022	2021
Millions
Net Loss	$(260.2)	$(260.2)
Prior Service Credit	0.1	1.0
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	89.0	93.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(171.1)	$(166.0)

Components of Net Periodic Pension Cost
Year Ended December 31	2022	2021	2020
Millions
Service Cost	$9.3	$11.0	$10.7
Non-Service Cost Components (a)
Interest Cost	27.2	24.6	27.9
Expected Return on Plan Assets	(41.5)	(43.4)	(42.7)
Amortization of Loss	11.4	18.8	12.8
Amortization of Prior Service Credit	(0.1)	(0.2)	(0.2)
Net Pension Cost	$6.3	$10.8	$8.5

(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	2022	2021
Millions
Net (Gain) Loss	$11.4	$(20.1)
Amortization of Prior Service Credit	0.1	0.2
Prior Service Credit Arising During the Period	0.8	—
Amortization of Loss	(11.4)	(18.8)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$0.9	$(38.7)

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2022	2021
Millions
Projected Benefit Obligation	$739.7	$911.7
Accumulated Benefit Obligation	$724.5	$875.5
Fair Value of Plan Assets	$568.6	$745.7

ALLETE, Inc. 2022 Form 10-K

114

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Postretirement Health and Life Obligation and Funded Status
As of December 31	2022	2021
Millions
Change in Benefit Obligation
Obligation, Beginning of Year	$148.2	$167.6
Service Cost	3.0	3.6
Interest Cost	4.4	4.4
Actuarial Gain (a)	(38.7)	(19.7)
Benefits Paid	(9.2)	(10.6)
Participant Contributions	2.7	2.9
Obligation, End of Year	$110.4	$148.2
Change in Plan Assets
Fair Value, Beginning of Year	$201.8	$186.0
Actual Return on Plan Assets	(33.0)	22.8
Employer Contribution	0.3	0.7
Participant Contributions	2.7	2.9
Benefits Paid	(9.2)	(10.6)
Fair Value, End of Year	$162.6	$201.8
Funded Status, End of Year	$52.2	$53.6
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$58.8	$64.8
Current Liabilities	$(0.2)	$(1.4)
Non-Current Liabilities	$(6.4)	$(9.8)

(a)Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

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 $11.8 million in irrevocable grantor trusts included in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2022 ($13.2 million as of December 31, 2021).

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	2022	2021
Millions
Net Gain	$(9.2)	$(12.7)
Prior Service Credit	(13.2)	(20.7)
Total Unrecognized Postretirement Health and Life Cost	$(22.4)	$(33.4)

ALLETE, Inc. 2022 Form 10-K

115

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2022	2021
Millions
Net Gain (a)	$9.2	$12.7
Prior Service Credit	13.2	20.7
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	29.8	20.2
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$52.2	$53.6

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

Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2022	2021	2020
Millions
Service Cost	$3.0	$3.6	$3.3
Non-Service Cost Components (a)
Interest Cost	4.4	4.4	5.0
Expected Return on Plan Assets	(9.6)	(9.9)	(9.7)
Amortization of Loss	0.4	3.0	1.0
Amortization of Prior Service Credit	(7.5)	(7.6)	(8.0)
Effect of Plan Curtailment	—	—	(0.3)
Net Postretirement Health and Life Credit	$(9.3)	$(6.5)	$(8.7)

(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	2022	2021
Millions
Net (Gain) Loss	$3.9	$(32.7)
Amortization of Prior Service Credit	7.5	7.6
Amortization of Loss	(0.4)	(3.0)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$11.0	$(28.1)

Estimated Future Benefit Payments	Pension	Postretirement Health and Life
Millions
2023	$58.0	$7.2
2024	$58.4	$7.5
2025	$58.0	$7.5
2026	$57.3	$7.7
2027	$57.0	$8.0
Years 2028 – 2032	$274.9	$42.4

ALLETE, Inc. 2022 Form 10-K

116

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Weighted Average Assumptions Used to Determine Benefit Obligation
As of December 31	2022	2021
Discount Rate
Pension	5.70%	3.05%
Postretirement Health and Life	5.68%	3.09%
Rate of Compensation Increase	3.58%	3.58%
Health Care Trend Rates
Trend Rate	6.50%	5.66%
Ultimate Trend Rate	5.00%	4.50%
Year Ultimate Trend Rate Effective	2038	2038

Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2022	2021	2020
Discount Rate
Pension	3.28%	2.87%	3.52%
Postretirement Health and Life	3.09%	2.70%	3.45%
Expected Long-Term Return on Plan Assets
Pension	6.00%	6.50%	6.75%
Postretirement Health and Life	5.41%	5.85%	6.08%
Rate of Compensation Increase	3.58%	3.62%	4.06%

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, 2022, considered a modified PRI-2012 mortality table and MP-2021 mortality projection scale.

ALLETE, Inc. 2022 Form 10-K

117

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Actual Plan Asset Allocations	Pension		Postretirement Health and Life (a)
	2022	2021	2022	2021
Equity Securities	46%	49%	66%	70%
Fixed Income Securities	50%	48%	34%	29%
Private Equity	—	—	—	1%
Real Estate	4%	3%	—	—
	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, 2022 (no shares as of December 31, 2021).

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, 2022:

Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	49	%	65	%
Fixed Income Securities	50	%	35	%
Real Estate	1	%	—
	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 7. Fair Value.)

ALLETE, Inc. 2022 Form 10-K

118

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Pension Fair Value

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—	$61.2	—	$61.2
U.S. Mid-cap Growth (a)	—	40.0	—	40.0
U.S. Small-cap (a)	—	35.4	—	35.4
International	$127.0	—	—	127.0
Fixed Income Securities (a)	—	275.3	—	275.3
Cash and Cash Equivalents	7.3	—	—	7.3
Real Estate	—	—	$22.4	22.4
Total Fair Value of Assets	$134.3	$411.9	$22.4	$568.6

(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	Real Estate
Millions
Balance as of December 31, 2021	$21.6
Actual Return on Plan Assets	1.0
Purchases, Sales, and Settlements – Net	(0.2)
Balance as of December 31, 2022	$22.4

	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
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.

ALLETE, Inc. 2022 Form 10-K

119

NOTE 12. 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, 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

Postretirement Health and Life Fair Value

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap	$26.7	—	—	$26.7
U.S. Mid-cap Growth	25.5	—	—	25.5
U.S. Small-cap	12.7	—	—	12.7
International	41.5	—	—	41.5
Fixed Income Securities:
Mutual Funds	55.5	—	—	55.5
Cash and Cash Equivalents	0.7	—	—	0.7
Total Fair Value of Assets	$162.6	—	—	$162.6

(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, 2021	$2.0
Actual Return on Plan Assets	(1.5)
Purchases, Sales, and Settlements – Net	(0.5)
Balance as of December 31, 2022	—

ALLETE, Inc. 2022 Form 10-K

120

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

	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

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 13. 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 $12.0 million in 2022 ($11.5 million in 2021; $11.2 million in 2020).

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, 2022, 2021 and 2020.

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 0.8 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.6 million of these shares remain available for issuance as of December 31, 2022.

ALLETE, Inc. 2022 Form 10-K

121

NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

The following types of share-based awards were outstanding in 2022, 2021 or 2020:

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	2022	2021	2020
Millions
Performance Shares	$0.7	$2.0	$2.2
Restricted Stock Units	0.9	1.0	0.9
Total Share-Based Compensation Expense	$1.6	$3.0	$3.1
Income Tax Benefit	$0.5	$0.9	$0.9

There were no capitalized share-based compensation costs during the years ended December 31, 2022, 2021 or 2020.

As of December 31, 2022, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $1.9 million and $0.8 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. 2022 Form 10-K

122

NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

Performance Shares. The following table presents information regarding our non-vested performance shares.

	2022		2021		2020
	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	80,661	$75.80	85,284	$80.73	99,585	$72.78
Granted (a)	37,731	$67.22	33,304	$73.25	25,763	$83.17
Awarded	—	—	—	—	(25,304)	$62.03
Unearned Grant Award	(50,524)	$77.49	(33,375)	$86.09	(13,625)	$62.03
Forfeited	(7,379)	$71.00	(4,552)	$74.05	(1,135)	$79.81
Non-vested as of December 31	60,489	$69.62	80,661	$75.80	85,284	$80.73

(a)    Shares granted include accrued dividends.

There were approximately 51,000 performance shares granted in February 2023 for the three-year performance period ending in 2025. 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 $3.4 million. There were no performance shares awarded in February 2023.

Restricted Stock Units. The following table presents information regarding our available restricted stock units.

	2022		2021		2020
	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	28,141	$73.16	37,482	$77.64	39,943	$69.30
Granted (a)	15,477	$63.70	16,251	$64.97	15,169	$83.48
Awarded	(7,396)	$75.55	(23,631)	$74.53	(17,193)	$63.41
Forfeited	(2,658)	$66.44	(1,961)	$74.52	(437)	$77.52
Available as of December 31	33,564	$68.80	28,141	$73.16	37,482	$77.64

(a)    Shares granted include accrued dividends.

There were approximately 14,700 restricted stock units granted in February 2023 for the vesting period ending in 2025. The grant date fair value of the restricted stock units granted was $0.9 million. There were approximately 8,500 restricted stock units awarded in February 2023. The grant date fair value of the shares awarded was $0.7 million.

NOTE 14. BUSINESS SEGMENTS

We present two reportable segments: Regulated Operations and ALLETE Clean Energy. 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. We also present Corporate and Other which includes three operating segments, New Energy, a renewable energy development company, 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, land holdings in Minnesota, and earnings on cash and investments.

ALLETE, Inc. 2022 Form 10-K

123

NOTE 14. BUSINESS SEGMENTS (Continued)

Year Ended December 31	2022	2021	2020
Millions
Operating Revenue
Residential	$175.9	$160.8	$140.7
Commercial	187.2	168.6	139.5
Municipal	40.2	52.0	41.2
Industrial	589.0	565.5	432.8
Other Power Suppliers	165.8	168.7	138.8
Other	101.2	112.3	94.3
Total Regulated Operations	1,259.3	1,227.9	987.3
ALLETE Clean Energy
Long-term PSA	77.2	75.5	68.3
Sale of Wind Energy Facility	33.5	—	—
Other	7.6	11.4	11.3
Total ALLETE Clean Energy	118.3	86.9	79.6
Corporate and Other
Long-term Contract	89.2	84.4	86.0
Sale of Renewable Development Projects	73.9	—	—
Other	30.0	20.0	16.2
Total Corporate and Other	193.1	104.4	102.2
Total Operating Revenue	$1,570.7	$1,419.2	$1,169.1
Net Income Attributable to ALLETE (a)
Regulated Operations	$149.9	$129.1	$136.3
ALLETE Clean Energy	16.3	26.3	21.1
Corporate and Other (b)(c)	23.1	13.8	8.0
Total Net Income Attributable to ALLETE	$189.3	$169.2	$165.4

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. 

(b)    Net Income in 2022 includes a $8.3 million after-tax expense as a result of purchase price accounting related to projects under development at the time of acquisition and $2.7 million after-tax of transaction costs related to the acquisition of New Energy.

(c)    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. 2022 Form 10-K

124

NOTE 14. BUSINESS SEGMENTS (Continued)

Year Ended December 31	2022	2021	2020
Millions
Depreciation and Amortization
Regulated Operations	$171.9	$170.7	$166.9
ALLETE Clean Energy	58.6	49.2	37.9
Corporate and Other	11.7	11.8	13.0
Total Depreciation and Amortization	$242.2	$231.7	$217.8
Impairment of Property, Plant and Equipment
ALLETE Clean Energy	—	—	$12.7
Interest Expense (a)
Regulated Operations	$58.1	$57.3	$58.5
ALLETE Clean Energy	2.3	1.5	2.2
Corporate and Other	19.6	13.2	13.2
Eliminations	(4.8)	(2.9)	(8.3)
Total Interest Expense	$75.2	$69.1	$65.6
Equity Earnings
Regulated Operations	$19.3	$21.3	$22.3
Corporate and Other	(0.6)	(1.3)	(0.2)
Total Equity Earnings	$18.7	$20.0	$22.1
Income Tax Expense (Benefit)
Regulated Operations	$(10.4)	$(16.6)	$(19.4)
ALLETE Clean Energy	(15.4)	(16.6)	(23.0)
Corporate and Other	(5.4)	6.3	(1.0)
Total Income Tax Benefit	$(31.2)	$(26.9)	$(43.4)

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.    

As of December 31	2022	2021
Millions
Assets
Regulated Operations	$4,291.4	$4,289.4
ALLETE Clean Energy	1,873.3	1,706.7
Corporate and Other	680.9	426.2
Total Assets	$6,845.6	$6,422.3
Capital Expenditures
Regulated Operations	$158.3	$166.8
ALLETE Clean Energy	2.2	269.9
Corporate and Other	47.6	39.7
Total Capital Expenditures	$208.1	$476.4

ALLETE, Inc. 2022 Form 10-K

125

NOTE 15. 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
2022
Operating Revenue	$383.5	$373.1	$388.3	$425.8
Operating Income	$53.4	$13.7	$33.4	$33.7
Net Income Attributable to ALLETE	$66.3	$37.6	$33.7	$51.7
Earnings Per Share of Common Stock
Basic	$1.24	$0.67	$0.59	$0.90
Diluted	$1.24	$0.67	$0.59	$0.90
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 (a)
Operating Revenue	$311.6	$243.2	$293.9	$320.4
Operating Income	$60.2	$12.7	$41.6	$23.7
Net Income Attributable to ALLETE	$66.3	$20.1	$40.7	$38.3
Earnings Per Share of Common Stock
Basic	$1.28	$0.39	$0.78	$0.74
Diluted	$1.28	$0.39	$0.78	$0.73

(a)    See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

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
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	—	—	—	—	—
2022 Trade Accounts Receivable	$1.8	$1.9	—	$2.1	$1.6
Finance Receivables – Long-Term	—	—	—	—	—
Deferred Asset Valuation Allowance
2020 Deferred Tax Assets	$70.0	$(0.1)	—	—	$69.9
2021 Deferred Tax Assets	$69.9	$(0.9)	—	—	$69.0
2022 Deferred Tax Assets	$69.0	$(8.8)	—	—	$60.2

(a)    Includes uncollectible accounts written-off.

ALLETE, Inc. 2022 Form 10-K

126

EX-10.(E)8

Exhibit 10(e)8

ALLETE Executive Annual Incentive Plan

Form of Award

Effective 2023

[Eligible Executive Employees]

Target Award Opportunity

Base Salary	$
Times
Award Opportunity (percent of base salary)	%
Equals
Target Award	$

Performance Levels and Award Amounts

Goal Performance Level	Payout as Percent of Target Award	Award Amount
Superior	200%	$
Target	100%	$
Threshold	44%	$
Below Threshold	0%	$

Goals

		Goal
		Weighting
Financial Goals
	Net Income	50%
	Cash from Operating Activities	20%
Strategic & Operational & Values Goals		30%
		100%

Compensation Subject to Compensation Recovery Policy

Annual Incentive Plan Compensation is subject to recoupment as defined in the Compensation Recovery policy.

EX-10.(E)9

Exhibit 10(e)9

ALLETE Executive Annual Incentive Plan

Form of Award

Effective 2023

[Eligible ALLETE Clean Energy Employees]

Target Award Opportunity

Base Salary	$
Times
Award Opportunity (percent of base salary)	%
Equals
Target Award	$

Performance Levels and Award Amounts

Goal Performance Level	Payout as Percent of Target Award	Award Amount
Superior	200%	$
Target	100%	$
Threshold	50%	$
Below Threshold	0%	$

Goals

		Goal
		Weighting
Financial Goals
	ALLETE Net Income	15%
	ALLETE Clean Energy Net Income	45%
Strategic and Operational & Values Goals		40%
		100%

Compensation Subject to Compensation Recovery Policy

Annual Incentive Plan Compensation is subject to recoupment as defined in the Compensation Recovery policy.

EX-10.(H)16

Exhibit 10(h)16

ALLETE

    EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

    RESTRICTED STOCK UNIT GRANT

Name

In accordance with the terms of ALLETE’s Executive Long-Term Incentive Compensation Plan, as amended (the "Plan"), and as determined by and through the Executive Compensation Committee of ALLETE’s Board of Directors, ALLETE hereby grants to you (the "Participant") Restricted Stock Units (“RSU’s”) as set forth below, payable in the form of ALLETE Common Stock, subject to the terms and conditions set forth in this Grant, including Annex A hereto, and all documents incorporated herein by reference:

    Number of Restricted Stock Units:    #        

    Date of Grant:                February 2, 2023    

    Vesting Period:            Period ending December 31, 2025        

This Grant is made in accordance with the Plan.

Further terms and conditions of the Grant are set forth in Annex A hereto, which is an integral part of this Grant.

Any term, provision or condition applicable to the Restricted Stock Units set forth in the Plan and not set forth herein is hereby incorporated by reference. To the extent any provision hereof is inconsistent with a Plan provision, the Plan provision will govern.

YOU SHOULD CAREFULLY READ AND REVIEW THE TERMS AND CONDITIONS SET FORTH IN THIS GRANT, INCLUDING ANNEX A HERETO, WHICH CONTAINS IMPORTANT INFORMATION, INCLUDING MANDATORY CLAIMS AND ARBITRATION PROCEDURES.

You will be deemed to have accepted this Grant on the Date of Grant, and all its associated terms and conditions, including the mandatory claims and arbitration procedures set forth in Annex A, unless you notify the Company of your non-acceptance of the Grant by contacting the Director – Human Resources, in writing within sixty (60) days of the Date of Grant.

IN WITNESS WHEREOF, ALLETE has caused this Grant to be executed by its Chair, President and Chief Executive Officer as of the date and year first above written.

    ALLETE

By:

Exhibit 10(i)17

Attachment: Annex A

PSGA1.doc

                        2

ANNEX A

TO

ALLETE

EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

RESTRICTED STOCK UNIT GRANT

    The grant of restricted stock units (each, a “RSU”) under the ALLETE Executive Long-Term Incentive Compensation Plan (the “Plan”), evidenced by the Grant to which this is annexed, is subject to the following additional terms and conditions:

1.    Form and Timing of Payment. Subject to the provisions hereof, each RSU will be paid in the form of one share of ALLETE common stock (each, a “Share”), plus accrued Dividend Equivalents. Shares will be deposited into your ALLETE Invest Direct plan account. Except as otherwise provided in sections 3 and 4, below, payment will be made during the period ending sixty days after the end of the vesting period; provided, however, the Participant will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Payment will be subject to withholding Shares equal in value to the minimum amount of tax required to be withheld by law.

2.    Dividend Equivalents. You will receive Dividend Equivalents in connection with the RSUs granted. Dividend Equivalents will be calculated and credited to you at the time the underlying RSUs are paid. Dividend Equivalents will be in the form of additional RSUs, which will be added to the number of RSUs subject to the grant, and will equal the number of Shares (including fractional Shares) that could have been purchased on applicable dividend payment dates, based on the closing ALLETE common stock price as reported in the consolidated transaction reporting system on that date, with cash dividends that would have been paid on the underlying RSUs, if such RSUs were Shares. Dividend Equivalents will only become payable if and to the extent the underlying RSUs vest and become payable.

3.    Payment Upon Retirement, Death or Disability; Forfeiture Upon Other Termination of Employment, Default on Certain Agreements or Unsatisfactory Job Performance.

3.1    Subject to Section 3.4 below, if during the vesting period you (i) Retire, (ii) die while employed by a Related Company, or (iii) become Disabled, a portion of the unvested RSUs subject to the Grant will vest and be paid to you (or your beneficiary or estate) during the period ending sixty days after such event; provided, however, you will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Except as otherwise provided in Section 4, payment pursuant to this Section 3.1 will be prorated, after giving effect to accumulated Dividend Equivalents, based on the number of whole calendar months within the vesting period that had elapsed as of the date of Retirement, death or Disability in relation to the number of calendar months in the vesting period. For purposes of this calculation, you will be credited with a whole month if you were employed on the 15th of the month.

3.2     Except as otherwise provided in Section 4, if during the vesting period or prior to payment of all RSUs you have a Separation from Service for any reason other than those specified in Section 3.1 above, all unvested or unpaid RSUs subject to the Grant (and related Dividend Equivalents) will be forfeited on the date of such Separation from Service.

3.3    If during the vesting period or prior to payment of all RSUs you are demoted, you default on any written agreement with a Related Company related to a restrictive employment covenant (such as confidentiality, non-disclosure, non-competition, non-

Exhibit 10(i)17

solicitation, or the like), or if ALLETE determines, in its sole discretion, that your job performance is unsatisfactory, ALLETE may cancel or amend your grant relating to any unpaid RSUs, resulting in the forfeiture of some portion or all of your unpaid RSUs (and related Dividend Equivalents).

3.4    Notwithstanding anything herein to the contrary, if you become entitled to a payment of the RSUs by reason of your Retirement and if you are a Specified Employee on the date of such Retirement, payment shall not be made until the earlier of: (i) the expiration of the six-month period beginning on the date of your Retirement, or (ii) the date of your death. The payment to which a Specified Employee would otherwise be entitled during this six-month period shall be paid, together with Dividend Equivalents that have accrued during this six-month delay, during the seventh month following the date of the Participant’s Retirement, or, if earlier, the date of the Participant’s death.

4.    Change in Control. Upon a Change in Control, unless the Committee provides otherwise prior to the Change in Control, outstanding unvested RSUs shall be prorated (as described below) and such prorated RSUs shall immediately vest and be payable to you during the period ending sixty days after the Change in Control. The RSUs will not be subject to proration and immediately vest, however, if and to the extent that the Grant is, in connection with the Change in Control, fully assumed by the successor corporation or parent thereof; in such case, the RSUs shall be prorated and immediately vest upon your termination of employment by the successor corporation for reasons other than cause within 18 months following the Change in Control and be payable to the Participant during the period ending sixty days after the termination of employment. Any payment on account of or in connection with a Change in Control will be prorated, after giving effect to the accumulation of Dividend Equivalents, based on the number of whole calendar months within the vesting period that had elapsed as of the date of the Change in Control or termination of employment, as applicable, in relation to the number of calendar months in the vesting period. For purposes of this calculation, you will be credited with a whole month if you were employed on the 15th of the month. In no event will you be permitted, directly or indirectly, to designate the taxable year of the distribution on account of or in connection with a Change in Control.

5.    Compensation Recovery Policy. The Grant is subject to the terms of any compensation recovery policy or policies established by ALLETE as may be amended from time to time (“Compensation Recovery Policy”). ALLETE hereby incorporates into the Grant the terms of the Compensation Recovery Policy.

6.     Section 409A Compliance. This Grant is intended to comply with Section 409A or an exemption thereunder, and, accordingly, to the maximum extent permitted, the Plan and the Grant shall be interpreted and administered in compliance therewith. Notwithstanding any other provision of the Grant, payments provided pursuant to the Grant may only be made upon an event and in a manner that complies with Section 409A or an applicable exemption. Any payments pursuant to the Grant that may be excluded from Section 409A as a short-term deferral shall be excluded from Section 409A to the maximum extent possible. To the extent that any provision of the Grant would cause a conflict with the requirements of Section 409A or would cause the administration of the Grant to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment. ALLETE makes no representation that the Grant complies with Section 409A and in no event shall ALLETE be liable for the payment of any taxes and penalties that you may incur under Section 409A.

7.     Claims Procedure and Arbitration. The Grant is subject to the following claims procedures:

4

Exhibit 10(i)17

    7.1    Mandatory Claims Procedures. If you or any person acting on your behalf (the “Claimant”) has any claim or dispute related in any way to the Grant or to the Plan, the Claimant must follow these claims procedures. All claims must be brought no later than one year following the date on which the claim first arose and any claim not submitted within such time limit will be waived.

    7.2    Claim Submission. Any claim must be made in writing to the Claims Administrator. The Claims Administrator, or its delegate, shall notify the Claimant of the resolution of the Claim within 90 days after receipt of the claim; provided, however, if the Claims Administrator determines that an extension is necessary, the 90-day period shall be extended to up to 180 days upon notice to that effect to the Claimant.

    7.3    Notice of Denial. If a claim is wholly or partially denied, the denial notice shall contain (i) the reason or reasons for denial of the claim, and (ii) references to the pertinent Plan provisions upon which the denial is based. Unless the claim is submitted for arbitration as provided below and in the Plan, the Claims Administrator’s decision or action shall be final, conclusive and binding on all persons having any interest in the Plan.

    7.4    Arbitration. If, after exhausting the procedures set forth above, a Claimant wishes to pursue legal action, any action by the Claimant with respect to a claim, must be resolved by arbitration in the manner described herein.

1)Time Limits. A Claimant seeking arbitration of any determination by the Claims Administrator must, within six (6) months of the date of the Claims Administrator’s final decision, file a demand for arbitration with the American Arbitration Association submitting the Claim to resolution by arbitration. A Claimant waives any claim not filed timely in accordance with this Section.

2)Rules Applicable to Arbitration. The arbitration process shall be conducted in accordance with the Commercial Law Rules of the American Arbitration Association.

3)Venue. The arbitration shall be conducted in Minneapolis, Minnesota.

4)Binding Effect. The decision of the arbitrator with respect to the claim will be final and binding upon the Company and the Claimant. BY PARTICIPATING IN THE PLAN, AND ACCEPTING THE GRANT, YOU, ON BEHALF OF YOURSELF AND ANY PERSON WITH A CLAIM RELATING TO YOUR GRANT, AGREE TO WAIVE ANY RIGHT TO SUE IN COURT OR TO PURSUE ANY OTHER LEGAL RIGHT OR REMEDY THAT MIGHT OTHERWISE BE AVAILABLE IN CONNECTION WITH THE RESOLUTION OF THE CLAIM.

5)Enforceability. Judgment upon any award entered by an arbitrator may be entered in any court having jurisdiction over the parties.

6)Waiver of Class, Collective, and Representative Actions.  Any claim shall be heard without consolidation of such claims with any other person or entity.  To the fullest extent permitted by law, whether in court or in arbitration, by participating in the Plan, you waive any right to commence, be a party to in any way, or be an actual or putative class member of any

5

Exhibit 10(i)17

class, collective, or representative action arising out of or relating to any claim, and you agree that any claim may only be initiated or maintained and decided on an individual basis. 

7)Standard of Review. Any decision of an arbitrator on a claim shall be limited to determining whether the Claims Administrator’s decision or action was arbitrary or capricious or was unlawful. The arbitrator shall adhere to and apply the deferential standard of review set out in Conkright v. Frommert, 130 S. Ct. 1640 (2010), Metropolitan Life Insurance Co. v. Glenn, 554 U.S. 105 (2008), and Firestone Tire and Rubber Company v. Bruch, 489 U.S. 101 (1989), and shall accord due deference to the determinations, interpretations, and construction of the Plan document by the Claim’s Administrator.

8)General Procedures.

i.Arbitration Rules. The arbitration hearing will be conducted under the AAA Commercial Arbitration Rules (as amended or revised from time to time by AAA) (hereinafter the “AAA Rules”), before one AAA arbitrator who is from the Large, Complex Case Panel and who has experience with matters involving executive compensation and equity compensation plans. The AAA Rules and the terms and procedures set forth here may conflict on certain issues. To the extent that the procedures set forth here conflict with the AAA Rules, the procedures set forth here shall control and be applied by the arbitrator. Notwithstanding the amount of the claim, the Procedures for Large, Complex Commercial Disputes shall not apply.

ii.Substantive Law. The arbitrator shall apply the substantive law (and the laws of remedies, if applicable), of Minnesota or federal law, or both, depending upon the claim. Except to the extent required by applicable law, the Claimant shall keep any arbitration decision or award strictly confidential and not disclose to anyone other than his or her spouse, attorney, or tax advisor.

iii.Authority. The arbitrator shall have jurisdiction to hear and rule on prehearing disputes and is authorized to hold prehearing conferences by telephone or in person as the arbitrator deems necessary. The arbitrator will have the authority to hear a motion to dismiss and/or a motion for summary judgment by any party and in doing so shall apply the standards governing such motions under the Federal Rules of Civil Procedure.

iv.Pre-Hearing Procedures. Each party may take the deposition of not more than one individual and the expert witness, if any, designated by another party. Each party will have the right to subpoena witnesses in accordance with the Federal Arbitration Act, Title 9 of the United States Code. Additional discovery may be had only if the arbitrator so orders, upon a showing of substantial need.

v.Fees and Costs. Administrative arbitration fees and arbitrator compensation shall be borne equally by the parties, and each party shall be responsible for its own attorney’s fees, if any; provided, however, that the Committee will authorize payment by the Company of all

6

Exhibit 10(i)17

administrative arbitration fees, arbitrator compensation and attorney’s fees if the Committee concludes that a Claimant has substantially prevailed on his or her claims. Unless prohibited by statute, the arbitrator shall assess attorney’s fees against a party upon a showing that such party’s claim, defense or position is frivolous, or unreasonable, or factually groundless. If either party pursues a claim by any means other than those set forth in this Article, the responding party shall be entitled to dismissal of such action, and the recovery of all costs and attorney’s fees and losses related to such action, unless prohibited by statute.

(9)Interstate Commerce and the Federal Arbitration Act. The Company is involved in transactions involving interstate commerce, and the employee’s employment with the Company involves such commerce. Therefore, the Federal Arbitration Act, Title 9 of the United States Code, will govern the interpretation, enforcement, and all judicial proceedings regarding the arbitration procedures in this Section.

8.    Ratification of Actions. By receiving the Grant or other benefit under the Plan, you and each person claiming under or through you shall be conclusively deemed to have indicated your acceptance and ratification of, and consent to, any action taken under the Plan or the Grant by ALLETE, the Board, or the Committee.

9.No Impact on Other Benefits. The Grant or payment on account thereof shall not be taken into account in determining any benefits under any severance, retirement, welfare, insurance or other benefit plan of ALLETE or any affiliate except to the extent otherwise expressly provided in writing in such other plan or an agreement thereunder.

10.    Notices. Any notice hereunder to ALLETE shall be addressed to ALLETE, 30 West Superior Street, Duluth, Minnesota 55802, Attention: Director – Human Resources, and any notice hereunder to you shall be directed to your address as indicated by ALLETE’s records, subject to the right of either party to designate at any time hereafter in writing some other address.

11.    Governing Law and Severability. To the extent not preempted by the Federal law, the Grant will be governed by and construed in accordance with the laws of the State of Minnesota, without regard to its conflicts of law provisions. In the event any provision of the Grant shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Grant, and the Grant shall be construed and enforced as if the illegal or invalid provision had not been included.

12.    Definitions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan. The following definitions apply to the Grant and this Annex A:

12.1    “Claims Administrator” means ALLETE’s Chief Executive Officer, unless the claimant is (or is acting on behalf of) an ALLETE executive officer (within the meaning of Exchange Act Rule 3b-7), in which case the Claims Administrator is the Executive Compensation Committee of the Board of Directors.    

12.2    “Change in Control” means the earliest of:

(a)the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires ownership of stock of the Company that, together with stock

7

Exhibit 10(i)17

previously held by the acquirer, constitutes more than fifty (50%) percent of the total fair market value or total voting power of Company stock. If any one Person, or more than one Person acting as a group, is considered to own more than fifty (50%) percent of the total fair market value or total voting power of Company stock, the acquisition of additional stock by the same Person or Persons acting as a group does not cause a Change in Control. An increase in the percentage of stock owned by any one Person, or Persons acting as a group, as a result of a transaction in which Company acquires its stock in exchange for property, is treated as an acquisition of stock;

(b)the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) ownership of Company stock possessing at least thirty (30%) percent of the total voting power of Company stock;

(c)the date a majority of the members of the Company’s board of directors is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of appointment or election; or

(d)the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) assets from the Company that have a total gross fair market value equal to at least forty (40%) percent of the total gross fair market value of all the Company’s assets immediately prior to the acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the corporation’s assets, or the value of the assets being disposed of, without regard to any liabilities associated with these assets.

In determining whether a Change in Control occurs, the attribution rules of Code section 318 apply to determine stock ownership. The stock underlying a vested option is treated as owned by the individual who holds the vested option, and the stock underlying an unvested option is not treated as owned by the individual who holds the unvested option. The term “Person” used in this definition means any individual, corporation (including any non-profit corporation), general, limited or limited liability partnership, limited liability company, joint venture, estate, trust, firm, association, organization or other entity or any governmental or quasi-governmental authority, organization, agency or body.

12.3    “Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.

12.4    “Disability” or “Disabled” means a physical or mental condition in which the Participant is:

(a)unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;

8

Exhibit 10(i)17

(b)by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer’s accident and health plan;

(c)determined to be totally disabled by the Social Security Administration; or

(d)disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

12.5    “Related Company” means the ALLETE, Inc. and all persons with whom the ALLETE, Inc. would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

12.6    “Retirement” or “Retires” means Separation from Service, for reasons other than death or Disability, on or after attaining normal retirement age or early retirement age as defined in the most applicable qualified retirement plan sponsored by the Related Company that employed the Participant immediately preceding the Separation from Service, without regard to whether the Participant is a participant in such plan, or if the employer Related Company does not sponsor such retirement plan, on or after attaining Normal Retirement Age or Early Retirement Age as defined in the ALLETE and Affiliated Companies Retirement Plan A, without regard to whether the Participant is a participant under the ALLETE and Affiliated Companies Retirement Plan A.

12.7     “Section 409A”means Section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, or other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

12.8    “Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by

9

Exhibit 10(i)17

contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies.

12.9    “Specified Employee” means an Participant who is subject to the six-month delay rule described in Code section 409A(2)(B)(i), determined in accordance with guidelines adopted by the Board from time to time as permitted by Section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, and other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

10

EX-10.(H)17

Exhibit 10(h)17

ALLETE

    EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

    PERFORMANCE SHARE GRANT

Name

In accordance with the terms of ALLETE’s Executive Long-Term Incentive Compensation Plan, as amended (the "Plan"), and as determined by and through the Executive Compensation Committee of ALLETE’s Board of Directors, ALLETE hereby grants to you (the "Participant") Performance Shares, as set forth below, subject to the terms and conditions set forth in this Grant, including Annex A and Annex B hereto and all documents incorporated herein by reference:

Number of Performance Shares Granted: #

[#]–Total Shareholder Return Metric #

[#]–Compound Annual Growth Rate Metric #

Date of Grant: February 2, 2023

Performance Period: January 1, 2023 through December 31, 2025

Performance Goals: See Annex B

This Grant is made in accordance with the Plan.

Further terms and conditions of the Grant are set forth in Annex A hereto and Performance Goals are set forth in Annex B hereto, both of which are integral parts of this Grant.

Any term, provision or condition applicable to the Performance Shares set forth in the Plan and not set forth herein is hereby incorporated by reference. To the extent any provision hereof is inconsistent with a Plan provision, the Plan provision will govern.

YOU SHOULD CAREFULLY READ AND REVIEW THE TERMS AND CONDITIONS SET FORTH IN THIS GRANT, INCLUDING ANNEX A HERETO, WHICH CONTAINS IMPORTANT INFORMATION, INCLUDING MANDATORY CLAIMS AND ARBITRATION PROCEDURES.

You will be deemed to have accepted this Grant on the Date of Grant and all its associated terms and conditions, including the mandatory claims and arbitration procedures set forth in Annex A, unless you notify the Company of your non-acceptance of the Grant by contacting the Director – Human Resources, in writing within sixty (60) days of the Date of Grant.

IN WITNESS WHEREOF, ALLETE has caused this Grant to be executed by its Chair, President and Chief Executive Officer as of the date and year first above written.

    ALLETE

By:

Exhibit 10(i)15

Attachments:    Annex A and Annex B

PSGA1.doc

                        2

ANNEX A

TO

ALLETE

EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN

PERFORMANCE SHARE GRANT

    The Performance Share Grant to which this is annexed is subject to the following additional terms and conditions:

    1.    Dividend Equivalents. You will receive Dividend Equivalents with respect to Performance Shares that are earned and payable. Dividend Equivalents are calculated and credited to you after the Performance Period has ended. The Dividend Equivalents will be in the form of additional Performance Shares, which will be added to the number of Performance Shares earned, and will equal the number of Shares (including fractional Shares) that could have been purchased on applicable dividend payment dates, based on the closing ALLETE common stock price as reported in the consolidated transaction reporting system on that date, with cash dividends that would have been paid on underlying Performance Shares, if such Performance Shares were Shares. Dividend Equivalents will only become payable if and to the extent the underlying Performance Shares are earned and become payable.

    2.    Satisfaction of Goals. Performance Shares remain unearned unless and until Performance Goals are achieved. After the Performance Period has ended, the Executive Compensation Committee (the “Committee”) will determine the extent to which the Performance Goals have been met. You will not earn any Performance Shares if the threshold performance level has not been met. Subject to the provisions of Section 4 below and to provisions in the Plan for change in control, Performance Shares will be earned as follows: If the threshold level has been met, you will have earned 50% of the Performance Shares (as increased by the Dividend Equivalents). If the target level has been met, you will have earned 100% of the Performance Shares (as increased by the Dividend Equivalents). If the superior level has been met, you will have earned 200% of the Performance Shares (as increased by the Dividend Equivalents). Straight line interpolation will be used to determine earned awards based on achievement of goals between the threshold, target and superior levels.

    3.    Payment. Subject to the provisions of Section 4 below and to provisions in the Plan for Change in Control, Performance Shares (as increased by the Dividend Equivalents) shall be paid in full after the Committee has determined the extent to which Performance Goals have been met and within two and one half months after the end of the Performance Period. Payment shall be made, after withholding Performance Shares in an amount equal in value to the minimum amount of tax required to be withheld by law, by depositing ALLETE common stock into your Invest Direct account. Performance Share awards shall not vest until paid.

    4.    Payment Upon Death, Retirement or Disability; Forfeiture of Unvested Performance Shares Upon Demotion, Unsatisfactory Job Performance, Default on Certain Agreements or Other Separation from Service.

4.1    If during a Performance Period you (i) Retire, (ii) die while employed by a Related Company, or (iii) become Disabled, you (or your beneficiary or estate) will receive a payment of any Performance Shares (as increased by the Dividend Equivalents) after the end of the Performance Period in accordance with Section 3 above. The payment shall be prorated based upon the number of whole calendar months within the Performance Period which had elapsed as of the date of death, Retirement or Disability in relation to the number of calendar months in the full Performance Period. A whole month is counted in the calculation if you were in the position as of the 15th of the month.

4.2     If after the end of a Performance Period, but before any or all Performance Shares have been paid, you Retire, die or become Disabled, you (or your beneficiary or estate) will be entitled to full payout of all earned Performance Shares (as increased by the Dividend Equivalents) in accordance with Section 3 above.

4.3    If, prior to payment of all Performance Shares, you are demoted, you default on any written agreement with a Related Company related to a restrictive employment covenant (such as confidentiality, non-disclosure, non-competition, non-solicitation, or the like) or ALLETE determines, in its sole discretion, that your job performance is unsatisfactory, ALLETE reserves the right to cancel or amend your grant relating to any unpaid Performance Shares, with the result that some portion or all of your unpaid Performance Shares (and related Dividend Equivalents) will be forfeited.

4.4    If you have a Separation from Service for any reason other than those specified in subsection 4.1 above, all Performance Shares (and related Dividend Equivalents), to the extent not yet paid, shall be forfeited on the date of such Separation from Service, except as otherwise provided by the Committee.

    5.    Compensation Recovery Policy. The Grant is subject to the terms of any compensation recovery policy or policies established by ALLETE as may be amended from time to time (“Compensation Recovery Policy”). ALLETE hereby incorporates into the Grant the terms of the Compensation Recovery Policy.

    6.    Section 409A Compliance. This Grant is intended to comply with Section 409A of the Code (“Section 409A”) or an exemption thereunder, and, accordingly, to the maximum extent permitted, the Plan and the Grant shall be interpreted and administered in compliance therewith. Notwithstanding any other provision of the Grant, payments provided pursuant to the Grant may only be made upon an event and in a manner that complies with Section 409A or an applicable exemption. Any payments pursuant to the Grant that may be excluded from Section 409A as a short-term deferral shall be excluded from Section 409A to the maximum extent possible. To the extent that any provision of the Grant would cause a conflict with the requirements of Section 409A or would cause the administration of the Grant to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment. ALLETE makes no representation that the Grant complies with Section 409A and in no event shall ALLETE be liable for the payment of any taxes and penalties that you may incur under Section 409A.

7.    Claims Procedure and Arbitration. The Grant is subject to the following claims procedures:

    7.1    Mandatory Claims Procedures. If you or any person acting on your behalf (the “Claimant”) has any claim or dispute related in any way to the Grant or to the Plan, the Claimant must follow these claims procedures. All claims must be brought no later than one year following the date on which the claim first arose and any claim not submitted within such time limit will be waived.

    7.2    Claim Submission. Any claim must be made in writing to the Claims Administrator. The Claims Administrator, or its delegate, shall notify the Claimant of the resolution of the claim within 90 days after receipt of the claim; provided, however, if the Claims Administrator determines that an extension is necessary, the 90-day period shall be extended to up to 180 days upon notice to that effect to the Claimant.

    7.3    Notice of Denial. If a claim is wholly or partially denied, the denial notice shall contain (i) the reason or reasons for denial of the claim, and (ii) references to the pertinent Plan provisions upon which the denial is based. Unless the claim is submitted for arbitration as provided below and in the Plan, the Claims Administrator’s decision or action shall be final, conclusive and binding on all persons having any interest in the Plan.

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    7.4    Arbitration. If, after exhausting the procedures set forth above, a Claimant wishes to pursue legal action, any action by the Claimant with respect to a claim, must be resolved by arbitration in the manner described herein.

1)Time Limits. A Claimant seeking arbitration of any determination by the Claims Administrator must, within six (6) months of the date of the Claims Administrator’s final decision, file a demand for arbitration with the American Arbitration Association submitting the claim to resolution by arbitration. A Claimant waives any claim not filed timely in accordance with this Section.

2)Rules Applicable to Arbitration. The arbitration process shall be conducted in accordance with the Commercial Law Rules of the American Arbitration Association.

3)Venue. The arbitration shall be conducted in Minneapolis, Minnesota.

4)Binding Effect. The decision of the arbitrator with respect to the claim will be final and binding upon the Company and the Claimant. BY PARTICIPATING IN THE PLAN, AND ACCEPTING THE GRANT, YOU, ON BEHALF OF YOURSELF AND ANY PERSON WITH A CLAIM RELATING TO YOUR GRANT, AGREE TO WAIVE ANY RIGHT TO SUE IN COURT OR TO PURSUE ANY OTHER LEGAL RIGHT OR REMEDY THAT MIGHT OTHERWISE BE AVAILABLE IN CONNECTION WITH THE RESOLUTION OF THE CLAIM.

5)Enforceability. Judgment upon any award entered by an arbitrator may be entered in any court having jurisdiction over the parties.

6)Waiver of Class, Collective, and Representative Actions.  Any claim shall be heard without consolidation of such claims with any other person or entity.  To the fullest extent permitted by law, whether in court or in arbitration, by participating in the Plan, you waive any right to commence, be a party to in any way, or be an actual or putative class member of any class, collective, or representative action arising out of or relating to any claim, and you agree that any claim may only be initiated or maintained and decided on an individual basis. 

7)Standard of Review. Any decision of an arbitrator on a claim shall be limited to determining whether the Claims Administrator’s decision or action was arbitrary or capricious or was unlawful. The arbitrator shall adhere to and apply the deferential standard of review set out in Conkright v. Frommert, 130 S. Ct. 1640 (2010), Metropolitan Life Insurance Co. v. Glenn, 554 U.S. 105 (2008), and Firestone Tire and Rubber Company v. Bruch, 489 U.S. 101 (1989), and shall accord due deference to the determinations, interpretations, and construction of the Plan document by the Claims Administrator.

8)General Procedures.

i.Arbitration Rules. The arbitration hearing will be conducted under the AAA Commercial Arbitration Rules (as amended or revised from time to time by AAA) (hereinafter the “AAA Rules”), before one AAA arbitrator who is from the Large, Complex Case Panel and who has experience with matters involving executive compensation and equity compensation plans. The AAA Rules and the terms and procedures set forth here may conflict on certain issues. To the extent that the procedures set forth here conflict with the AAA Rules, the procedures set forth here shall control and be applied by the

3

arbitrator. Notwithstanding the amount of the claim, the Procedures for Large, Complex Commercial Disputes shall not apply.

ii.Substantive Law. The arbitrator shall apply the substantive law (and the laws of remedies, if applicable), of Minnesota or federal law, or both, depending upon the claim. Except to the extent required by applicable law, the Claimant shall keep any arbitration decision or award strictly confidential and not disclose to anyone other than his or her spouse, attorney, or tax advisor.

iii.Authority. The arbitrator shall have jurisdiction to hear and rule on prehearing disputes and is authorized to hold prehearing conferences by telephone or in person as the arbitrator deems necessary. The arbitrator will have the authority to hear a motion to dismiss and/or a motion for summary judgment by any party and in doing so shall apply the standards governing such motions under the Federal Rules of Civil Procedure.

iv.Pre-Hearing Procedures. Each party may take the deposition of not more than one individual and the expert witness, if any, designated by another party. Each party will have the right to subpoena witnesses in accordance with the Federal Arbitration Act, Title 9 of the United States Code. Additional discovery may be had only if the arbitrator so orders, upon a showing of substantial need.

v.Fees and Costs. Administrative arbitration fees and arbitrator compensation shall be borne equally by the parties, and each party shall be responsible for its own attorney’s fees, if any; provided, however, that the Committee will authorize payment by the Company of all administrative arbitration fees, arbitrator compensation and attorney’s fees if the Committee concludes that a Claimant has substantially prevailed on his or her claims. Unless prohibited by statute, the arbitrator shall assess attorney’s fees against a party upon a showing that such party’s claim, defense or position is frivolous, or unreasonable, or factually groundless. If either party pursues a claim by any means other than those set forth in this Article, the responding party shall be entitled to dismissal of such action, and the recovery of all costs and attorney’s fees and losses related to such action, unless prohibited by statute.

(9)Interstate Commerce and the Federal Arbitration Act. The Company is involved in transactions involving interstate commerce, and the employee’s employment with the Company involves such commerce. Therefore, the Federal Arbitration Act, Title 9 of the United States Code, will govern the interpretation, enforcement, and all judicial proceedings regarding the arbitration procedures in this Section.

8.    Ratification of Actions. By receiving the Grant or other benefit under the Plan, you and each person claiming under or through you shall be conclusively deemed to have indicated your acceptance and ratification of, and consent to, any action taken under the Plan or the Grant by ALLETE, the Board or the Committee.

9.    No Impact on Other Benefits. The Grant or payment on account thereof shall not be taken into account in determining any benefits under any severance, retirement, welfare, insurance or other benefit plan of ALLETE or any affiliate except to the extent otherwise expressly provided in writing in such other plan or an agreement thereunder.

    10.    Notices. Any notice hereunder to ALLETE shall be addressed to ALLETE, 30 West Superior Street, Duluth, Minnesota 55802, Attention: Director – Human Resources, and any notice hereunder to you shall be directed to your address as indicated by ALLETE’s records, subject to the right of either party to designate at any time hereafter in writing some other address.

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11.    Governing Law and Severability. To the extent not preempted by the Federal law, the Grant will be governed by and construed in accordance with the laws of the State of Minnesota, without regard to its conflicts of law provisions. In the event any provision of the Grant shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Grant, and the Grant shall be construed and enforced as if the illegal or invalid provision had not been included.

    12.    Definitions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan. The following definitions apply to the Grant and this Annex A:

12.1    “Claims Administrator” means ALLETE’s Chief Executive Officer, unless the claimant is (or is acting on behalf of) an ALLETE executive officer (within the meaning of Exchange Act Rule 3b-7), in which case the Claims Administrator is the Executive Compensation Committee of the Board of Directors.

12.2    “Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.

12.3    “Disability” or “Disabled” means a physical or mental condition in which the Participant is:

(1)unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;

(2)by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer’s accident and health plan;

(3)determined to be totally disabled by the Social Security Administration; or

(4)disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

12.4    “Related Company” means ALLETE, Inc. and all persons with whom the ALLETE, Inc. would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

12.5    “Retirement” or “Retires” means Separation from Service, for reasons other than death or Disability, on or after attaining normal retirement age or early retirement age as defined in the most applicable qualified retirement plan sponsored by the Related Company that employed the Participant immediately preceding the Separation from Service, without regard to whether the Participant is a participant in such plan, or if the employer Related Company

5

does not sponsor such retirement plan, on or after attaining Normal Retirement Age or Early Retirement Age as defined in the ALLETE and Affiliated Companies Retirement Plan A, without regard to whether the Participant is a participant under the ALLETE and Affiliated Companies Retirement Plan A.

    12.6    “Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies.

6

Effective 2023

[Eligible Executive Employees]

ANNEX B

TO

ALLETE

EXECUTIVE LONG TERM INCENTIVE COMPENSATION PLAN

    PERFORMANCE SHARE GRANT

Financial Measure:

Fifty percent (50%) of the total performance share opportunity is based on Total Shareholder Return (TSR) computed over the three-year performance period January 1, 2023 to December 31, 2025.

Fifty percent (50%) of the total performance share opportunity is based on the Company’s Compound Annual Growth Rate (CAGR) computed over the three-year performance period January 1, 2023 to December 31, 2025.

Performance Share Award (TSR metric):

Achievement will be weighted on TSR performance in accordance with ALLETE’s TSR ranking as follows: at the 85th percentile or higher among the peer group (superior performance), 200% of the weighted Performance Share Grant will be earned. If ALLETE’s TSR ranking is at the 50th percentile among the peer group (target performance), 100% of the weighted Performance Share Grant will be earned. If ALLETE’s TSR ranking is at the 30th percentile (threshold performance), 50% of the weighted Performance Share Grant will be earned. If TSR ranking is below threshold, no weighted Performance Shares will be earned. Straight-line interpolation will be used to determine earned awards based on the TSR ranking between threshold, target and superior.

Peer Group:

The integrated utility companies comprising Edison Electric Institute (EEI) Stock Index as of December 31, 2025 that have been in the EEI Stock Index for at least three years as of December 31, 2025 will constitute the peer group used to determine actual payout results. The table below lists the EEI Stock Index as of December 31, 2022, based on published information available as of that date:

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Alliant Energy Corporation	Entergy Corporation	Otter Tail Corporation
Ameren Corporation	Evergy Inc.	PG&E Corporation
American Electric Power Company	Eversource Energy	Pinnacle West Capital Corporation
Avangrid, Inc.	Exelon Corporation	PNM Resources, Inc.
Avista Corporation	FirstEnergy Corporation	Portland General Electric Company
Black Hills Corporation	Hawaiian Electric Industries, Inc.	PPL Corporation
CenterPoint Energy, Inc.	IDACORP, Inc.	Public Service Enterprise Group, Inc.
CMS Energy Corporation	MDU Resources Group, Inc.	Sempra Energy
Consolidated Edison, Inc.	MGE Energy, Inc.	The Southern Company
Dominion Energy, Inc.	NextEra Energy, Inc.	Unitil Corporation
DTE Energy Company	NiSource, Inc.	WEC Energy Group, Inc.
Duke Energy Corporation	NorthWestern Corporation	Xcel Energy, Inc.
Edison International	OGE Energy Corp.

Any Company that is no longer included in the EEI Stock Index as of December 31, 2025 due to corporate restructuring during the performance period (e.g., mergers, acquisitions, divestitures, spin-offs, etc.) will be excluded from the results calculation entirely. If a corporate restructuring during the performance period results in a company remaining in the EEI Stock Index following the transaction (and thus not being excluded from the results calculation entirely), from the point of the transaction forward, the results calculation will track only the entity that remains in the EEI Stock Index and ignore other entities, regardless of whether such other entities are publicly traded.

Performance Share Award (CAGR metric):

CAGR will be calculated by using the baseline pro forma Earnings per Share (EPS) for the year ending December 31 of the year prior to the beginning of the three-year performance period and the pro forma EPS at the end of the three-year performance period. Achievement will be weighted on CAGR performance in accordance with the following table:

Compound Annual Growth Rate	Payout Percentage (% of Target Award)
Superior 8%	200%
Target 6%	100%
Threshold 4%	50%

If CAGR percentage result is below threshold, no weighted Performance Shares will be earned. Straight-line interpolation will be used to determine earned awards based on the CAGR percentage result between threshold, target and superior.

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EX-10.(K)6

Exhibit 10(j)6

ALLETE, INC.

Non-Employee Director Compensation

Effective January 1, 2023

Board Retainers (1) (2) Stock Cash	$110,000 $85,000
Committee Cash Retainers (1) (2) Audit Executive Compensation & Human Capital Corporate Governance & Nominating	$10,000 $10,000 $10,000
Chair Cash Retainers (1) (2) Audit Executive Compensation & Human Capital Corporate Governance & Nominating	$12,000 $7,500 $5,000

Lead Director (1) (2) (3) Board Stock Retainer Board Cash Retainer Lead Director Cash Retainer Committee Cash Retainers $110,000 $85,000 $25,000 $30,000

(1)Cash and stock retainers may be deferred under the Director Compensation Deferral Plan II.

(2)Cash retainers may be elected to be received in ALLETE stock.

(3)In 2023, Lead Director pay was restructured to include committee cash retainers.

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

As of December 31, 2022

Name of Organization (a)	State or Country
ALLETE, Inc. (d/b/a ALLETE; Minnesota Power; Minnesota Power, Inc.;	Minnesota
Minnesota Power & Light Company)
ALLETE Automotive Services, LLC	Minnesota
ALLETE Enterprises, Inc.	Minnesota
ALLETE Clean Energy, Inc.	Minnesota
ACE O&M, LLC	Delaware
ACE Solar LLC	Delaware
ACE Wind LLC	Delaware
ACE Mid-West Holdings, LLC	Delaware
ACE Gopher Holdings, LLC	Delaware
ACE Lincoln Heights Holdings, LLC	Delaware
Cisco Holdings, LLC	Delaware
MWW Holdings, LLC	Delaware
Lake Benton Power Associates LLC	Delaware
Lake Benton Holdings LLC	Delaware
Lake Benton Power Partners L.L.C.	Delaware
Storm Lake Power Partners I LLC	Delaware
Storm Lake II Power Associates LLC	Delaware
Storm Lake II Holdings LLC	Delaware
Storm Lake Power Partners II LLC	Delaware
Red Barn Energy, LLC	Minnesota
Whitetail Wind, LLC	Minnesota
ACE South Holdings, LLC	Delaware
ACE Caddo Class B LLC	Delaware
ACE-SRE Caddo Holdings, LLC	Delaware
Caddo Holding Company, LLC	Delaware
Caddo Wind, LLC	Delaware
Diamond Spring QOZB, LLC	Delaware
ACE DS Class B LLC	Delaware
Diamond Spring, LLC	Delaware
ACE West Holdings, LLC	Delaware
ACE GAWW Class B LLC	Delaware
Great American West Wind, LLC	Delaware
Glen Ullin Energy Center, LLC	Delaware
South Peak Wind LLC	Delaware
Condon Wind Power, LLC	Delaware
Ruso Wind Partners, LLC	Delaware
Armenia Holdings, LLC	Delaware
AMW I Holding, LLC	Delaware
Armenia Mountain Wind, LLC	Delaware
Armenia Mountain Wind II, LLC	Delaware
Thunder Spirit Wind, LLC	Delaware
ALLETE Enterprises QOF, LLC	Delaware
ALLETE Power Systems, Inc.	Minnesota
ALLETE Renewable Resources, Inc.	North Dakota
ALLETE Transmission Holdings, Inc.	Wisconsin
ASW Partners, LLC	Delaware
ALLETE South Wind, LLC	Delaware
Nobles 2 Power Partners, LLC	Delaware

Exhibit 21

Name of Organization (a)	State or Country
BNI Energy, Inc.	North Dakota
BNI Coal, Ltd.	North Dakota
DLS Manager, LLC	Delaware
DLS Holdco, LLC	Delaware
MP Affiliate Resources, Inc.	Minnesota
New Energy Equity LLC	Delaware
Rainy River Energy Corporation	Minnesota
South Shore Energy, LLC	Wisconsin
Upper Minnesota Properties, Inc.	Minnesota
Upper Minnesota Properties - Development, Inc.	Minnesota
ALLETE Properties, LLC (d/b/a ALLETE Properties)	Minnesota
ALLETE Commercial, LLC	Florida
Lehigh Acquisition, LLC	Delaware
Florida Landmark Communities, LLC	Florida
Interlachen Lakes Estates, LLC	Florida
Palm Coast Land, LLC	Florida
ALLETE Water Services, Inc.	Minnesota
Energy Land, Incorporated	Wisconsin
MP Investments, Inc.	Delaware
RendField Land Company, Inc.	Minnesota
Superior Water, Light and Power Company	Wisconsin

(a)Certain insignificant subsidiaries are omitted.

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-266383, 333-262769) and Form S-8 (Nos. 333-162890, 333-183051, 333-190336, 333-207846, 333-228120, 333-253190, 333-265211) of ALLETE, Inc. of our report dated February 16, 2023, relating to the financial statements, financial statement scheduleand the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Minneapolis, Minnesota

February 16, 2023

EX-31.A

Exhibit 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

I, Bethany M. Owen, certify that:

1.    I have reviewed this annual report on Form 10-K for the fiscal year ended December 31, 2022, of ALLETE, Inc.;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))  and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c.    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 16, 2023	/s/ Bethany M. Owen
		Bethany M. Owen
		Chair, President and Chief Executive Officer

EX-31.B

Exhibit 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

I, Steven W. Morris, certify that:

1.    I have reviewed this annual report on Form 10-K for the fiscal year ended December 31, 2022, of ALLETE, Inc.;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))  and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c.    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 16, 2023	/s/ Steven W. Morris
		Steven W. Morris
		Senior Vice President and Chief Financial Officer

EX-32

Exhibit 32

Section 1350 Certification of Periodic Report

By the Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, each of the undersigned officers of ALLETE, Inc. (ALLETE), does hereby certify that:

1.    The Annual Report on Form 10-K of ALLETE for the fiscal year ended December 31, 2022, (Report) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of ALLETE.

Date:	February 16, 2023	/s/ Bethany M. Owen
		Bethany M. Owen
		Chair, President and Chief Executive Officer

Date:	February 16, 2023	/s/ Steven W. Morris
		Steven W. Morris
		Senior Vice President and Chief Financial Officer

This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to liability pursuant to that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that ALLETE specifically incorporates it by reference.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ALLETE and will be retained by ALLETE and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95

Exhibit 95

Mine Safety Disclosure

Mine or Operating Name/MSHA Identification Number

Section 104 S&S Citations (#)

Section 104(b) Orders (#)

Section 104(d) Citations and Orders (#)

Section 110(b)(2) Violations (#)

Section 107(a) Orders (#)

Total Dollar Value of MSHA Assessments Proposed ($)

Total Number of Mining- Related Fatalities (#)

Received Notice of Pattern of Violation Under Section 104(e) (yes/no)

Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)

Legal Actions Pending as of Last Day of Period (#)

Legal Actions Initiated During Period (#)

Legal Actions Resolved During Period (#)

Center Mine / 3200218

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—

—

—

—

—

No

No

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—

—

For the year ended December 31, 2022, BNI Energy, owner of Center Mine, received six citations under Section 104(a) of the Mine Safety Act, none of which were significant and substantial (S&S) citations. For the year ended December 31, 2022, BNI Energy was assessed $820 in penalties for citations closed during the period. For the year ended December 31, 2022, there were no citations, orders, violations or notices received under Sections 104(b), 104(d), 107(a), 104(e) or 110(b)(2) of the Mine Safety Act and there were no fatalities.

EX-99

		Exhibit 99
	For Release:	February 16, 2023
	Investor Contact:	Vince Meyer
		218-723-3952
NEWS		vmeyer@allete.com

ALLETE, Inc. reports 2022 earnings of $3.38 per share;

Initiates 2023 earnings guidance range of $3.55 to $3.85 per share

DULUTH, Minn. - ALLETE, Inc. (NYSE: ALE) today reported 2022 earnings of $3.38 per share on net income of $189.3 million and operating revenue of $1.6 billion. Reported results from 2021 were $3.23 per share on net income of $169.2 million and operating revenue of $1.4 billion.

“I am proud of our many successes and accomplishments throughout 2022, all of which position ALLETE well now and into the future,” said ALLETE Chair, President, and CEO Bethany Owen. “The approval of Minnesota Power’s Integrated Resource Plan results in a $600 million dollar expansion of our capital expenditure plan and will drive rate base growth to 11 percent over the next five years. Minnesota Power also achieved near-perfect system reliability for its customers during the year, and we know that additional transmission investments will be critical to help ensure reliability as the clean-energy transformation continues. To that end, the MISO Tranche 1 approval of the Northern Reliability Project transmission line, and advancing the ALLETE and Grid United vision for the nation’s first transmission corridor to link three regional U.S. electric energy markets are important achievements in the year, which will drive significant future growth. With all of this, and the successful acquisition and integration of New Energy Equity expanding our presence in the growing solar sector – ALLETE’s strategic position is strong as the drive toward a clean-energy economy gains momentum.”

“In 2023, we will continue to advance these and other strategic initiatives that set the stage for meaningful future growth,” Owen continued. “ALLETE’s Sustainability in Action strategy provides significant value to our customers, our communities, and our investors, as well as exciting opportunities for our employees. While our financial results for 2022 were below our expectations, ALLETE’s future is very bright, with transformative clean-energy initiatives, significant infrastructure investments, and new opportunities with the distributed solar platform, pipeline, and strong team at New Energy.”

“Our financial performance in 2022 reflects Regulated Operations within our original guidance range, which included a full year of interim rate reserves recorded in the fourth quarter for the outcome of the Minnesota Power rate case,” said ALLETE Senior Vice President and Chief Financial Officer Steve Morris, “ALLETE Clean Energy and Corporate and Other businesses were below expectations of our guidance range for the year, primarily due to losses taken on the now-completed Northern Wind project and financial underperformance of facilities in the Southwest Power Pool market, where we are working to navigate market and contract volatility related to our Oklahoma wind facilities. I remain confident in our growth prospects driven by our expanded capital expenditure plan over the next five years and investment opportunities well into the future. In addition, I am pleased with the momentum and future growth at New Energy as the team exceeded the acquisition plan for the year while completing integration, entering multiple new markets and significantly expanding their pipeline of projects. We believe our unique mix of businesses will continue to deliver a strong value proposition to shareholders for years to come.”

Page 1 of 5

ALLETE 30 West Superior Street, Duluth, Minnesota 55802

ALLETE’s Regulated Operations segment, which includes Minnesota Power, Superior Water, Light and Power and the Company’s investment in the American Transmission Co., recorded net income of $149.9 million, compared to $129.1 million in 2021. Higher earnings in 2022 reflect the implementation of interim rates on January 1, 2022, net of interim rate reserves. This was partially offset by higher costs under a 250 MW power purchase agreement, higher operating and maintenance expense, and lower kilowatt-hour sales to industrial customers. ALLETE’s earnings in ATC were lower than in 2021 primarily due to period-over-period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints.

ALLETE Clean Energy recorded 2022 net income of $16.3 million compared to $26.3 million in 2021. Net income in 2022 reflected challenges under the Caddo and Diamond Spring wind energy facilities’ power sales agreements resulting from market volatility and transmission congestion in the Southwest Power Pool. Net income in 2022 also included additional losses related to ALLETE Clean Energy’s now completed and sold Northern Wind project. Net income in 2021 included the impact related to ALLETE Clean Energy’s Diamond Spring wind energy facility due to an extreme winter storm event in February 2021.

Corporate and Other businesses, which include New Energy, BNI Energy, the Company’s investment in the Nobles 2 wind energy facility, and ALLETE Properties, recorded net income of $23.1 million in 2022 compared to net income of $13.8 million in 2021. Net income in 2022 reflects net income from New Energy of $7.8 million, which was impacted by purchase price accounting. Net income in 2022 also reflects higher earnings from our investment in Nobles 2 due to higher wind resources in 2022, higher land sales at ALLETE Properties, and earnings from Minnesota solar projects placed into service in 2022. Partially offsetting these increases were transaction costs of $2.7 million after-tax related to the acquisition of New Energy, and higher other expenses compared to 2021. 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.

Details of the Company’s 2023 earnings guidance were filed as part of today’s Form 8-K filing.

Live Webcast on February 16, 2023; financial slides posted on company website

ALLETE’s earnings conference call will be at 10:00 a.m. (EST), February 16, 2023, at which time management will discuss 2022 financial results and 2023 earnings guidance. Interested parties may participate live by registering for the call at allete.com/earningscall or may listen to the live audio-only webcast accompanied by supporting slides, which will be available on ALLETE’s Investor Relations websiteinvestor.allete.com/events-presentations. The webcast will be accessible for one year at allete.com.

ALLETE is an energy company headquartered in Duluth, Minn. In addition to its electric utilities, Minnesota Power and Superior Water, Light and Power of Wisconsin, ALLETE owns ALLETE Clean Energy, based in Duluth, BNI Energy in Bismarck, N.D., New Energy Equity headquartered in Annapolis, MD, and has an eight percent equity interest in the American Transmission Co. More information about ALLETE is available at www.allete.com. ALE-CORP

The statements contained in this release and statements that ALLETE may make orally in connection with this release that are not historical facts, are forward-looking statements. Actual results may differ materially from those projected in the forward-looking statements. These forward-looking statements involve risks and uncertainties and investors are directed to the risks discussed in documents filed by ALLETE with the Securities and Exchange Commission.

ALLETE's press releases and other communications may include certain non-Generally Accepted Accounting Principles (GAAP) financial measures. A "non-GAAP financial measure" is defined as a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements.

Page 2 of 5

ALLETE 30 West Superior Street, Duluth, Minnesota 55802

Non-GAAP financial measures utilized by the Company include presentations of earnings (loss) per share. ALLETE's management believes that these non-GAAP financial measures provide useful information to investors by removing the effect of variances in GAAP reported results of operations that are not indicative of changes in the fundamental earnings power of the Company's operations. Management believes that the presentation of the non-GAAP financial measures is appropriate and enables investors and analysts to more accurately compare the company's ongoing financial performance over the periods presented.

Page 3 of 5

ALLETE 30 West Superior Street, Duluth, Minnesota 55802

ALLETE, Inc.

Consolidated Statement of Income

For the Periods Ended December 31, 2022 and 2021

	Quarter Ended		Year to Date
	2022	2021	2022	2021
Millions Except Per Share Amounts
Operating Revenue
Contracts with Customers – Utility	$299.0	$339.7	$1,259.3	$1,227.9
Contracts with Customers – Non-utility	125.5	56.5	303.8	179.9
Other – Non-utility	1.3	2.8	7.6	11.4
Total Operating Revenue	425.8	399.0	1,570.7	1,419.2
Operating Expenses
Fuel, Purchased Power and Gas – Utility	128.1	173.0	545.5	562.4
Transmission Services – Utility	19.2	19.2	76.7	75.3
Cost of Sales – Non-utility	85.9	21.0	182.8	68.8
Operating and Maintenance	80.8	59.1	318.9	259.2
Depreciation and Amortization	60.8	58.3	242.2	231.7
Taxes Other than Income Taxes	17.3	18.4	70.4	70.5
Total Operating Expenses	392.1	349.0	1,436.5	1,267.9
Operating Income	33.7	50.0	134.2	151.3
Other Income (Expense)
Interest Expense	(19.9)	(17.3)	(75.2)	(69.1)
Equity Earnings	5.6	5.7	18.7	20.0
Other	6.0	2.6	22.4	8.7
Total Other Expense	(8.3)	(9.0)	(34.1)	(40.4)
Income Before Non-Controlling Interest and Income Taxes	25.4	41.0	100.1	110.9
Income Tax Benefit	(11.8)	(7.6)	(31.2)	(26.9)
Net Income	37.2	48.6	131.3	137.8
Net Loss Attributable to Non-Controlling Interest	(14.5)	(13.3)	(58.0)	(31.4)
Net Income Attributable to ALLETE	$51.7	$61.9	$189.3	$169.2
Average Shares of Common Stock
Basic	57.2	52.8	55.9	52.4
Diluted	57.2	52.8	56.0	52.5
Basic Earnings Per Share of Common Stock	$0.90	$1.18	$3.38	$3.23
Diluted Earnings Per Share of Common Stock	$0.90	$1.18	$3.38	$3.23
Dividends Per Share of Common Stock	$0.65	$0.63	$2.60	$2.52

Consolidated Balance Sheet

Millions

	Dec. 31,	Dec. 31,		Dec. 31,	Dec. 31,
	2022	2021		2022	2021
Assets			Liabilities and Equity
Cash and Cash Equivalents	$36.4	$45.1	Current Liabilities	$716.2	$543.4
Other Current Assets	681.6	246.2	Long-Term Debt	1,648.2	1,763.2
Property, Plant and Equipment – Net	5,004.0	5,087.5	Deferred Income Taxes	158.1	181.8
Regulatory Assets	441.0	511.8	Regulatory Liabilities	526.1	536.1
Equity Investments	322.7	318.0	Defined Benefit Pension & Other Postretirement Benefit Plans	179.7	179.5
Goodwill and Intangibles – Net	155.6	0.8	Other Non-Current Liabilities	269.0	280.8
Other Non-Current Assets	204.3	212.9	Equity	3,348.3	2,937.5
Total Assets	$6,845.6	$6,422.3	Total Liabilities and Equity	$6,845.6	$6,422.3

Page 4 of 5

ALLETE 30 West Superior Street, Duluth, Minnesota 55802

	Quarter Ended		Year to Date
ALLETE, Inc.	December 31,		December 31,
Income (Loss)	2022	2021	2022	2021
Millions
Regulated Operations	$30.5	$29.7	$149.9	$129.1
ALLETE Clean Energy	1.3	14.6	16.3	26.3
Corporate and Other	19.9	17.6	23.1	13.8
Net Income Attributable to ALLETE	$51.7	$61.9	$189.3	$169.2
Diluted Earnings Per Share	$0.90	$1.18	$3.38	$3.23

Statistical Data
Corporate
Common Stock
High	$67.45	$66.71	$68.61	$73.10
Low	$47.77	$56.84	$47.77	$56.84
Close	$64.51	$66.35	$64.51	$66.35
Book Value	$47.03	$45.34	$47.03	$45.34

Kilowatt-hours Sold
Millions
Regulated Utility
Retail and Municipal
Residential	297	289	1,148	1,135
Commercial	332	341	1,359	1,359
Industrial	1,698	1,845	6,745	7,196
Municipal	121	145	540	590
Total Retail and Municipal	2,448	2,620	9,792	10,280
Other Power Suppliers	605	1,407	3,149	5,102
Total Regulated Utility	3,053	4,027	12,941	15,382

Regulated Utility Revenue
Millions
Regulated Utility Revenue
Retail and Municipal Electric Revenue
Residential	$33.4	$38.3	$156.7	$145.6
Commercial	42.7	41.4	178.5	161.0
Industrial	142.2	156.4	585.7	562.1
Municipal	8.3	13.5	40.2	52.0
Total Retail and Municipal	226.6	249.6	961.1	920.7
Other Power Suppliers	41.2	51.8	165.8	168.7
Other (Includes Water and Gas Revenue)	31.2	38.3	132.4	138.5
Total Regulated Utility Revenue	$299.0	$339.7	$1,259.3	$1,227.9

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.

Page 5 of 5

ALLETE 30 West Superior Street, Duluth, Minnesota 55802

XML

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 01, 2023	Jun. 30, 2022
Document and Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Document Transition Report	false
Entity File Number	1-3548
Entity Registrant Name	ALLETE, Inc.
Entity Incorporation, State	MN
Entity Tax Identification Number	41-0418150
Entity Address, Address Line	30 West Superior Street
Entity Address, City	Duluth
Entity Address, State	MN
Entity Address, Postal Zip Code	55802-2093
City Area Code	218
Local Phone Number	279-5000
Title of 12(b) Security	Common Stock, without par value
Trading Symbol	ALE
Security Exchange Name	NYSE
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 3,349,606,300
Entity Common Stock, Shares Outstanding		57,252,864
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
ICFR Auditor Attestation Flag	true

XML

Audit Information	12 Months Ended
	Dec. 31, 2022
Auditor Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Firm ID	238
Auditor Location	Minneapolis, MN

XML

Consolidated Balance Sheet - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Current Assets [Abstract]
Cash and Cash Equivalents	$ 36,400,000	$ 45,100,000
Accounts Receivable, Allowance	137,900,000	123,700,000
Inventories – Net	455,900,000	97,700,000
Prepayments and Other	87,800,000	24,800,000
Total Current Assets	718,000,000.0	291,300,000
Property, Plant and Equipment – Net	5,004,000,000	5,087,500,000
Regulatory Assets	441,000,000.0	511,800,000
Equity Investments	322,700,000	318,000,000.0
Goodwill and Intangible Assets – Net	155,600,000	800,000
Other Non-Current Assets	204,300,000	212,900,000
Total Assets	6,845,600,000	6,422,300,000
Current Liabilities [Abstract]
Accounts Payable	103,000,000.0	111,000,000.0
Accrued Taxes	69,100,000	65,100,000
Accrued Interest	20,500,000	20,100,000
Long-Term Debt Due Within One Year	272,600,000	214,200,000
Other	251,000,000.0	133,000,000.0
Total Current Liabilities	716,200,000	543,400,000
Long-Term Debt	1,648,200,000	1,763,200,000
Deferred Income Taxes	158,100,000	181,800,000
Regulatory Liabilities	526,100,000	536,100,000
Defined Benefit Pension and Other Postretirement Benefit Plans	179,700,000	179,500,000
Other Non-Current Liabilities	269,000,000.0	280,800,000
Total Liabilities	3,497,300,000	3,484,800,000
Commitments, Guarantees and Contingencies (Note 9)
ALLETE Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 57.2 and 53.2 Shares Issued and Outstanding	1,781,500,000	1,536,700,000
Accumulated Other Comprehensive Loss	(24,400,000)	(23,800,000)
Retained Earnings	934,800,000	891,400,000
Total ALLETE Equity	2,691,900,000	2,404,300,000
Non-Controlling Interest in Subsidiaries	656,400,000	533,200,000
Total Equity	3,348,300,000	2,937,500,000
Total Liabilities and Equity	$ 6,845,600,000	$ 6,422,300,000

XML

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.6	$ 1.8
Common Stock [Abstract]
Common Stock, Par Value Per Share	$ 0	$ 0
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Issued	57.2	53.2
Common Stock, Shares Outstanding	57.2	53.2

XML

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Revenue [Abstract]
Contracts with Customers – Utility	$ 1,259.3	$ 1,227.9	$ 987.3
Contracts with Customers – Non-utility	303.8	179.9	170.5
Other – Non-utility	7.6	11.4	11.3
Total Operating Revenue	1,570.7	1,419.2	1,169.1
Operating Expenses [Abstract]
Fuel, Purchased Power and Gas - Utility	545.5	562.4	358.6
Transmission Services - Utility	76.7	75.3	67.0
Cost of Sales - Non-utility	182.8	68.8	66.7
Operating and Maintenance	318.9	259.2	252.0
Depreciation and Amortization	242.2	231.7	217.8
Taxes Other than Income Taxes	70.4	70.5	56.1
Impairment of Property, Plant and Equipment	0.0	0.0	12.7
Total Operating Expenses	1,436.5	1,267.9	1,030.9
Operating Income	134.2	151.3	138.2
Other Income (Expense) [Abstract]
Interest Expense	(75.2)	(69.1)	(65.6)
Equity Earnings	18.7	20.0	22.1
Other	22.4	8.7	14.7
Total Other Expense	(34.1)	(40.4)	(28.8)
Income Before Non-Controlling Interest and Income Taxes	100.1	110.9	109.4
Income Tax Benefit	(31.2)	(26.9)	(43.4)
Net Income	131.3	137.8	152.8
Net Loss Attributable to Non-Controlling Interest	(58.0)	(31.4)	(12.6)
Net Income Attributable to ALLETE	$ 189.3	$ 169.2	$ 165.4
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	55.9	52.4	51.9
Diluted (Shares)	56.0	52.5	51.9
Basic Earnings Per Share of Common Stock	$ 3.38	$ 3.23	$ 3.18
Diluted Earnings Per Share of Common Stock	$ 3.38	$ 3.23	$ 3.18

XML

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Comprehensive Income [Abstract]
Net Income	$ 131.3	$ 137.8	$ 152.8
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities - Net of Income Tax Expense (Benefit) of $(0.2), $(0.1) and $0.1	(0.4)	(0.1)	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Tax Expense (Benefit) of $(0.1), $3.0 and $(3.1)	(0.2)	7.4	(7.6)
Total Other Comprehensive Income (Loss)	(0.6)	7.3	(7.5)
Total Comprehensive Income	130.7	145.1	145.3
Net Loss Attributable to Non-Controlling Interest	(58.0)	(31.4)	(12.6)
Total Comprehensive Income Attributable to ALLETE	$ 188.7	$ 176.5	$ 157.9

XML

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Unrealized Gain (Loss) on Securities, Income Tax Expense (Benefit)	$ (0.2)	$ (0.1)	$ 0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Tax Expense (Benefit)	$ (0.1)	$ 3.0	$ (3.1)

XML

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Activities
Net Income	$ 131.3	$ 137.8	$ 152.8
AFUDC – Equity	(2.7)	(2.6)	(1.9)
Income from Equity Investments – Net of Dividends	2.4	2.2	(3.2)
(Gain) / Loss on Investments and Property, Plant and Equipment	1.2	(0.8)	(1.3)
Loss on Impairment of Assets	0.0	0.0	12.7
Depreciation Expense	242.0	231.6	217.7
Amortization of PSAs	(7.6)	(11.4)	(11.3)
Amortization of Other Intangible Assets and Other Assets	8.3	9.9	10.4
Deferred Income Tax Benefit	(38.5)	(26.9)	(43.4)
Share-Based and ESOP Compensation Expense	4.9	5.9	6.1
Defined Benefit Pension and Other Postretirement Benefit Expense	(3.0)	4.3	0.1
Bad Debt Expense	1.9	1.2	2.7
Provision (Payments) for Tax Reform Refund	0.0	0.0	(0.2)
Fuel Adjustment Clause	15.1	(56.4)	5.0
Provision (Payments) for Interim Rate Refund	18.4	0.0	0.0
Changes in Operating Assets and Liabilities
Accounts Receivable	(14.0)	(13.0)	(18.2)
Inventories	(256.1)	(23.5)	(1.4)
Prepayments and Other	(21.5)	(0.5)	0.9
Accounts Payable	(1.3)	15.0	11.8
Other Current Liabilities	116.2	28.0	11.7
Cash Contributions to Defined Benefit Pension Plans	0.0	(10.3)	(10.7)
Changes in Regulatory and Other Non-Current Assets	24.1	(12.0)	(31.0)
Changes in Regulatory and Other Non-Current Liabilities	0.2	(15.0)	(9.5)
Cash provided by Operating Activities	221.3	263.5	299.8
Investing Activities
Proceeds from Sale of Available-for-sale Securities	2.2	6.4	12.8
Payments for Purchase of Available-for-sale Securities	(2.4)	(3.6)	(8.7)
Acquisitions of Subsidiaries – Net of Cash and Restricted Cash Acquired	(155.0)	0.0	0.0
Payments for Equity Investments	(5.9)	(17.6)	(99.1)
Additions to Property, Plant and Equipment	(220.5)	(479.5)	(724.7)
Other Investing Activities	(2.4)	9.1	6.9
Cash used in Investing Activities	(384.0)	(485.2)	(812.8)
Financing Activities
Proceeds from Issuance of Common Stock	248.0	69.9	18.1
Equity Issuance Costs	(8.1)	0.0	0.0
Proceeds from Issuance of Short-Term and Long-Term Debt	785.4	733.0	672.4
Repayments of Short-Term and Long-Term Debt	(877.0)	(552.9)	(488.6)
Proceeds from Non-Controlling Interest in Subsidiaries - Net of Issuance Costs	155.7	90.9	414.5
Dividends on Common Stock	(145.9)	(131.9)	(128.2)
Other Financing Activities	(2.9)	(4.8)	(2.5)
Cash provided by Financing Activities	155.2	204.2	485.7
Change in Cash, Cash Equivalents and Restricted Cash	(7.5)	(17.5)	(27.3)
Cash and Cash Equivalents	$ 40.2	$ 47.7	$ 65.2

XML

Consolidated Statement of Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Accumulated Other Comprehensive Loss [Member]	Retained Earnings [Member]	Non-Controlling Interest in Subsidiaries [Member]
Balance, Beginning of Period at Dec. 31, 2019		$ 1,436.7	$ (23.6)	$ 818.8	$ 103.7
Consolidated Statement of Equity [Roll Forward]
Common Stock Issued		24.2
Unrealized Gain (Loss) on Debt Securities	$ 0.1		0.1
Defined Benefit Pension and Other Postretirement Plans	(7.6)		(7.6)
Net Loss Attributable to Non-Controlling Interest	(12.6)				(12.6)
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities					0.0
Distributions to Non-Controlling Interest					0.0
Net Income Attributable to ALLETE	165.4			165.4
Common Stock Dividends	128.2			(128.2)
Adjustment of Redeemable Non-Controlling Interest				0.0
Proceeds from Non-Controlling Interest - Net of Issuance Costs	414.5				414.5
Balance, Ending of Period at Dec. 31, 2020	$ 2,791.4	1,460.9	(31.1)	856.0	505.6
Consolidated Statement of Equity [Roll Forward]
Dividends Per Share of Common Stock	$ 2.47
Common Stock Issued		75.8
Unrealized Gain (Loss) on Debt Securities	$ (0.1)		(0.1)
Defined Benefit Pension and Other Postretirement Plans	7.4		7.4
Net Loss Attributable to Non-Controlling Interest	(31.4)				(31.4)
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities					28.8
Distributions to Non-Controlling Interest					(3.1)
Net Income Attributable to ALLETE	169.2			169.2
Common Stock Dividends	131.9			(131.9)
Adjustment of Redeemable Non-Controlling Interest				(1.9)
Proceeds from Non-Controlling Interest - Net of Issuance Costs	90.9				90.9
Balance, Ending of Period at Dec. 31, 2021	$ 2,937.5	1,536.7	(23.8)	891.4	533.2
Consolidated Statement of Equity [Roll Forward]
Dividends Per Share of Common Stock	$ 2.52
Common Stock Issued		244.8
Unrealized Gain (Loss) on Debt Securities	$ (0.4)		(0.4)
Defined Benefit Pension and Other Postretirement Plans	(0.2)		(0.2)
Net Loss Attributable to Non-Controlling Interest	(58.0)				(58.0)
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities					0.0
Distributions to Non-Controlling Interest					(1.7)
Net Income Attributable to ALLETE	189.3			189.3
Common Stock Dividends	145.9			(145.9)
Adjustment of Redeemable Non-Controlling Interest				0.0
Proceeds from Non-Controlling Interest - Net of Issuance Costs	155.7				182.9
Balance, Ending of Period at Dec. 31, 2022	$ 3,348.3	$ 1,781.5	$ (24.4)	$ 934.8	$ 656.4
Consolidated Statement of Equity [Roll Forward]
Dividends Per Share of Common Stock	$ 2.60

XML

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$ 72.8	$ 66.8	$ 62.0
Cash Paid (Received) for Income Taxes		6.0	0.0	(2.0)
Noncash Investing and Financing Activities [Abstract]
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment		(9.6)	(14.0)	(67.0)
Reclassification of Property, Plant and Equipment to Inventory	[1]	99.7	0.0	0.0
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities	[2]	0.0	30.6	0.0
Capitalized Asset Retirement Costs		11.8	16.9	4.1
AFUDC–Equity		$ 2.7	$ 2.6	$ 1.9

[1] The decommissioning of the existing Northern Wind assets resulted in a reclassification from Property, Plant and Equipment – Net to Inventories – Net in the second quarter of 2022 as they were repowered and subsequently sold to a subsidiary of Xcel Energy Inc. In the third quarter of 2022, safe harbor equipment was transferred to the project entity resulting in an additional reclassification from Property, Plant and Equipment – Net to Inventories – Net.

[2] Amount reclassified to Current Liabilities resulting from the exercise of an option to buy out a non-controlling interest.

XML

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Operations and Significant Accounting Policies [Text Block]

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. The presentation of certain prior period amounts on the Consolidated Financial Statements have been adjusted for comparative purposes.

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 two reportable segments: Regulated Operations and ALLETE Clean Energy. 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 14 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 1,200 MW of nameplate capacity wind energy generation with a majority contracted under PSAs of various durations. In addition, 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 Clean Energy currently has approximately 100 MW of wind energy facilities under contract to be sold to others.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

New Energy is a renewable energy development company with a primary focus on solar and storage facilities while also offering comprehensive operations, maintenance and asset management services.

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 2027 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, 2022, is approximately $7 million.

BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2022, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 9. Commitments, Guarantees and Contingencies.)

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, 2022, and 2021, 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 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 amount also includes 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	2022	2021	2020
Millions
Cash and Cash Equivalents	$36.4	$45.1	$44.3
Restricted Cash included in Prepayments and Other	1.5	0.3	0.8
Restricted Cash included in Other Non-Current Assets	2.3	2.3	20.1
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows	$40.2	$47.7	$65.2

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flow Information.

Consolidated Statement of Cash Flows
Year Ended December 31	2022	2021	2020
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$72.8	$66.8	$62.0
Cash Paid (Received) for Income Taxes	$6.0	—	$(2.0)
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(9.6)	$(14.0)	$(67.0)
Reclassification of Property, Plant and Equipment to Inventory (a)	$99.7	—	—
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities (b)	—	$30.6	—
Capitalized Asset Retirement Costs	$11.8	$16.9	$4.1
AFUDC–Equity	$2.7	$2.6	$1.9

(a)The decommissioning of the existing Northern Wind assets resulted in a reclassification from Property, Plant and Equipment – Net to Inventories – Net in the second quarter of 2022 as they were repowered and subsequently sold to a subsidiary of Xcel Energy Inc. In the third quarter of 2022, safe harbor equipment was transferred to the project entity resulting in an additional reclassification from Property, Plant and Equipment – Net to Inventories – Net.

(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	2022	2021
Millions
Trade Accounts Receivable
Billed	$107.1	$100.6
Unbilled	29.2	24.7
Less: Allowance for Doubtful Accounts	1.6	1.8
Total Trade Accounts Receivable	134.7	123.5
Income Taxes Receivable	3.2	0.2
Total Accounts Receivable	$137.9	$123.7

Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to seven Large Power Customers. Receivables from these customers totaled $11.3 million as of December 31, 2022 ($7.8 million as of December 31, 2021). 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 2022, accounted for approximately 32 percent of Regulated Operations operating revenue and approximately 26 percent of consolidated operating revenue in 2022 (32 percent of Regulated Operations operating revenue and 28 percent of consolidated operating revenue in 2021 and 29 percent of Regulated Operations operating revenue and 25 percent of consolidated operating revenue in 2020).

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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Inventories – Net
As of December 31	2022	2021
Millions
Fuel (a)	$33.4	$18.7
Materials and Supplies	75.1	56.1
Construction of Wind Energy Facilities (b)	347.4	22.9
Total Inventories – Net	$455.9	$97.7

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

(b) Project costs related to ALLETE Clean Energy’s Northern Wind project sold in January 2023 and Red Barn wind project which is expected to be sold in the first half 2023. (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. The MPUC order for Minnesota Power’s 2015 IRP 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. Minnesota Power’s latest IRP, which was approved by the MPUC in an order dated January 9, 2023, includes ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. Boswell Unit 3 and Unit 4 have a net book value of approximately $235 million and $435 million, respectively, as of December 31, 2022. (See Note 4. Regulatory Matters.) Minnesota Power’s latest IRP also includes the retirement of Taconite Harbor. As of December 31, 2022, Taconite Harbor had a net book value of approximately $25 million. 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 decline in energy prices or lower wind resource expectations could result in a future impairment.

In 2022 and 2021 there were triggering events that indicated an impairment for our property, plant, and equipment at certain ALLETE Clean Energy wind energy facilities with expiring PSAs for which a recoverability test was performed indicating that the undiscounted cash flows adequately supported the property, plant and equipment book values. As a result, no impairment was recorded in 2022 and 2021. In 2020, there were indicators of impairment for ALLETE Clean Energy’s Northern Wind project. See Immaterial Revision to Prior Period.

Immaterial Revision to Prior Period. We have identified an immaterial prior period error with respect to the recognition of a non-cash impairment expense for our Northern Wind operating assets in the fourth quarter of 2020 prior to the execution of the purchase and sales agreement for a repower and sale of the wind energy facility. Specifically, the remaining net book value of the property, plant and equipment used in the recoverability test was calculated incorrectly. If the net book value would have been calculated correctly in the recoverability test, an $8.8 million after-tax impairment expense would have been recognized in the fourth quarter of 2020. We evaluated the effects of this error on our previously-issued consolidated financial statements in accordance with the guidance in Accounting Standards Codification Topic (ASC) 250, Accounting Changes and Error Corrections, ASC 250-10-S99-1, Assessing Materiality, and ASC 250-10-S99-2, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, and concluded that no prior period is materially misstated. Accordingly, we have revised our consolidated financial statements for the impacted prior periods herein.

A summary of the effect of the revision on the Consolidated Statements of Income and Consolidated Statement of Comprehensive Income for the year ended December 31, 2020 is as follows:

Revision Impacts for the Year Ended December 31, 2020	As Reported	Adjustment	As Revised
Millions Except Per Share Amounts
Impairment of Property, Plant and Equipment	—	$12.7	$12.7
Income Tax Benefit	$(39.5)	(3.9)	(43.4)
Net Income Attributable to ALLETE	$174.2	$(8.8)	$165.4
Comprehensive Income Attributable to ALLETE	$166.7	$(8.8)	$157.9
Diluted Earnings Per Share	$3.35	$(0.17)	$3.18

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

A summary of the effect of the revision on the Consolidated Balance Sheet as of December 31, 2021 is as follows:

Revision Impacts for the Year Ended December 31, 2021	As Reported	Adjustment	As Revised
Millions
Property, Plant and Equipment - Net	$5,100.2	$(12.7)	$5,087.5
Total Assets	$6,435.0	$(12.7)	$6,422.3
Deferred Income Taxes	$185.7	$(3.9)	$181.8
Total Liabilities	$3,488.7	$(3.9)	$3,484.8
Retained Earnings	$900.2	$(8.8)	$891.4
Total Equity	$2,946.3	$(8.8)	$2,937.5

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 13. Employee Stock and Incentive Plans.)

Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. Goodwill is assessed annually in the fourth quarter for impairment and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level.

As of the date of our annual goodwill impairment testing in 2022, the Company elected to bypass the qualitative assessment of goodwill for impairment, proceeding directly to the two-step impairment test for the New Energy reporting unit. In performing Step 1 of the impairment test, we compared the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the impairment test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

For Step 1 of the impairment test, we estimated the reporting unit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes a growth rate on debt-free cash flows. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. Our annual impairment test in 2022 indicated that the estimated fair value of New Energy exceeded its carrying value, and therefore no impairment existed. The fair value of the reporting unit was determined using a discounted cash flow model, using significant assumptions which included a discount rate of 14 percent, cash flow forecasts through 2027, industry average gross margins, and a terminal growth rate of 3.5 percent.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets
As of December 31	2022	2021
Millions
Contract Assets (a)	$21.0	$23.3
Operating Lease Right-of-use Assets	12.7	16.4
ALLETE Properties	19.1	19.4
Restricted Cash	2.3	2.3
Other Postretirement Benefit Plans	58.8	64.8
Other	90.4	86.7
Total Other Non-Current Assets	$204.3	$212.9

(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	2022	2021
Millions
Customer Deposits (a)	$150.7	$27.2
PSAs	6.1	12.6
Provision for Interim Rate Refund	18.4	—
Manufactured Gas Plant (b)	14.7	12.8
Fuel Adjustment Clause	—	5.0
Operating Lease Liabilities	3.2	4.8
Redeemable Non-Controlling Interest (c)	—	30.6
Other	57.9	40.0
Total Other Current Liabilities	$251.0	$133.0

(a)    Primarily related to deposits received by ALLETE Clean Energy for the Northern Wind project sold in January 2023 and the Red Barn wind project which is expected to be sold in the first half of 2023. (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 9. 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	2022	2021
Millions
Asset Retirement Obligation (a)	$200.4	$184.5
PSAs	26.9	39.5
Operating Lease Liabilities	9.3	11.6
Other	32.4	45.2
Total Other Non-Current Liabilities	$269.0	$280.8

(a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $32.4 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2022 ($28.5 million as of December 31, 2021).

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	2022	2021
Millions
Operating Lease Cost	$6.3	$6.7
Other Information:
Operating Cash Flows From Operating Leases	$6.3	$6.7

Additional information related to leases was as follows:

As of December 31	2022		2021
Millions
Balance Sheet Information Related to Leases:
Other Non-Current Assets	$12.7		$16.4
Total Operating Lease Right-of-use Assets	$12.7		$16.4
Other Current Liabilities	$3.2		$4.8
Other Non-Current Liabilities	9.3		11.6
Total Operating Lease Liabilities	$12.5		$16.4
Weighted Average Remaining Lease Term (Years):
Operating Leases - Vehicles and Equipment	4		3
Operating Leases - Land and Other	16		27
Weighted Average Discount Rate:
Operating Leases - Vehicles and Equipment	3.9	%	3.8	%
Operating Leases - Land and Other	3.9	%	4.5	%

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Maturities of lease liabilities were as follows:

	December 31, 2022
Millions
2023	$3.4
2024	3.1
2025	2.9
2026	2.9
2027	3.8
Thereafter	1.2
Total Lease Payments Due	17.3
Less: Imputed Interest	4.8
Total Lease Obligations	12.5
Less: Current Lease Obligations	3.2
Total Long-term Lease Obligations	$9.3

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 9. 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 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.

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 14 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. One of these 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 expiring in 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 52 percent of total regulated utility kWh sales for the year ended December 31, 2022. Within industrial revenue, Minnesota Power had seven Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2022. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2026 through 2029. 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 $55 million per annum through 2026, $15 million in 2027, and $25 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.

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 2024 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.

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.

Sale of Renewable Development Projects includes revenue recognized from development only and development plus construction type projects that are sold to a customer. For development only projects, revenue is recognized at point in time when all required development responsibilities have been completed and ownership has transferred to the customer. For development plus construction, the transaction price is allocated to two performance obligations based upon the standalone selling price of each obligation. Revenue is recognized on the development performance obligation upon satisfying all required development activities and ownership transferring to the customer. Revenue for the construction performance obligation is recognized over time based on construction costs incurred, beginning at notice to proceed through the commercial operation date.

Other primarily includes revenue from BNI Energy unrelated to coal, revenue from New Energy for asset management services and non-development activities, 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.

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, 2022, we have $21.0 million of assets recognized for costs incurred to obtain contracts with our customers ($23.3 million as of December 31, 2021). 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 $2.4 million of non-cash amortization for the year ended December 31, 2022 ($2.7 million for the year end December 31, 2021).

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 ownership percentage 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, 2022 and 2021, 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.

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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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	2022	2021	2020
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credit (a)	$9.8	$6.1	$8.6
Interest and Investment Earnings	—	2.3	1.6
AFUDC - Equity	2.7	2.6	1.9
Gain on Land Sales	—	0.1	0.4
PSA Liability (b)	10.2	—	—
Other	(0.3)	(2.4)	2.2
Total Other Income (Expense) - Other	$22.4	$8.7	$14.7

(a)These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)

(b)The gain on removal of the PSA liability for the Northern Wind project upon decommissioning of the legacy wind energy facility assets, which was more than offset by a reserve for an anticipated loss on the sale of the Northern Wind project, was recorded in Cost of Sales - Non-Utility on the Consolidated Statement of Income.

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. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal credits related to public utility 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 11. 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.

XML

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
As of December 31	2022	2021
Millions
Regulated Operations
Property, Plant and Equipment in Service	$5,198.6	$5,028.7
Construction Work in Progress	74.0	108.7
Accumulated Depreciation	(1,972.3)	(1,834.6)
Regulated Operations – Net	3,300.3	3,302.8
ALLETE Clean Energy
Property, Plant and Equipment in Service	1,619.4	1,704.2
Construction Work in Progress	51.1	79.9
Accumulated Depreciation	(176.8)	(149.0)
ALLETE Clean Energy – Net	1,493.7	1,635.1
Corporate and Other (a)
Property, Plant and Equipment in Service	295.2	267.1
Construction Work in Progress	50.9	19.8
Accumulated Depreciation	(136.1)	(137.3)
Corporate and Other – Net	210.0	149.6
Property, Plant and Equipment – Net	$5,004.0	$5,087.5

(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	1 to 50	ALLETE Clean Energy	5 to 35
Transmission	50 to 75	Corporate and Other	3 to 50
Distribution	18 to 70

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.)

NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)

Asset Retirement Obligations
Millions
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
Accretion	9.5
Liabilities Recognized	7.8
Liabilities Settled	(4.4)
Revisions in Estimated Cash Flows	3.0
Obligation as of December 31, 2022	$200.4

XML

Jointly-Owned Facilities and Assets

12 Months Ended

Dec. 31, 2022

Jointly-Owned Facilities and Assets [Abstract]

Jointly-Owned Facilities and Assets [Text Block]

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.

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, 2022
Boswell Unit 4	$712.0	$340.1	$3.3	80
Transmission Assets	101.0	21.1	—	9.3 - 14.7
Total	$813.0	$361.2	$3.3
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

XML

Regulatory Matters

12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

Regulatory Matters [Text Block]

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 $38.8 million in 2022 ($38.9 million in 2021; $29.9 million in 2020).

Minnesota Retail Rates. Minnesota Power’s retail rates through 2021 were based on a 2018 MPUC retail rate order that allowed 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.)

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. 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 are now 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.

At a hearing on January 23, 2023, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.65 percent and a 52.50 percent equity ratio. Upon commencement of final rates, we expect additional revenue from base rates of approximately $60 million and an additional $10 million in revenue recognized under cost recovery riders on an annualized basis, subject to final written order and reconsideration. Final rates are expected to commence in the third quarter of 2023; interim rates will be collected through this period with reserves recorded as necessary. As a result of the MPUC’s determinations made on January 23, 2023, Minnesota Power has recorded a reserve for an interim rate refund of approximately $18 million pre-tax as of December 31, 2022, which is subject to MPUC approval of Minnesota Power’s refund calculation. In addition, Minnesota Power recorded a charge of approximately $8 million pre-tax to write-off the deferred portion of residential customer interim rates. Minnesota Power also recorded additional revenue of approximately $9 million pre-tax for an increase in expected recoveries under its cost recovery riders. Impacts of regulatory outcomes that are determined subsequent to the balance sheet date, and prior to issuance of the financial statements, are recognized in the financial statements as of the balance sheet date.

FERC-Approved Wholesale Rates. Minnesota Power has wholesale contracts with 14 non-affiliated municipal customers in Minnesota and SWL&P. Two 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 is effective through December 31, 2037. The wholesale electric service contract with SWL&P is effective through February 28, 2026. 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.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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.

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 an MPUC order dated December 27, 2022, which provisionally approved Minnesota Power’s latest transmission factor filing submitted on October 31, 2022.

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 2020 order. On February 2, 2022, Minnesota Power submitted its latest renewable factor filing, which included a request to recover a regulatory asset of $3.8 million related to the recognition of production tax credits due to a metering error at Bison. The filing was approved in an order dated January 24, 2023 authorizing Minnesota Power to include updated billing rates on customer bills for recovery of the regulatory asset.

Solar Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place to charge retail customers on a current basis for solar costs related to investments and expenditures for meeting the state of Minnesota’s solar energy standard. Current customer billing rates for the solar cost recovery rider were approved by the MPUC in an order dated August 31, 2022.

Electric Vehicle Charging Infrastructure Petition. In April 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 October 2021 order, the MPUC approved Minnesota Power’s petition.

Fuel Adjustment Clause. In 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 through December 31, 2021. Minnesota Power submitted its annual true-up filing and a significant events filing in March 2022 requesting recovery of these under-collected fuel adjustment clause recoveries. The MPUC approved recovery of the regulatory asset in an order dated July 5, 2022; recovery of the regulatory asset will continue through mid-2023.

Minnesota Power also incurred higher fuel and purchased power costs in 2022 than those factored in its fuel adjustment forecast filed in May 2021 for 2022, which resulted in the recognition of an approximately $13 million regulatory asset as of December 31, 2022. Minnesota Power filed a significant events filing in June 2022 requesting to increase rates from August 2022 through December 2022 in order to recover the under-collected fuel adjustment clause recoveries that were expected for 2022. No parties objected to the request and higher rates were implemented in August 2022. Minnesota Power will request recovery of the remaining regulatory asset as part of its annual true-up filing expected to be submitted to the MPUC in March 2023.

In 2020, Minnesota Power filed its FAC report covering the period July 2018 through December 2019. In a 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, and refunded to customers in 2022.

Wisconsin Retail Rates. SWL&P’s retail rates through 2022 were based on a December 2018 order by the PSCW that allowed for a return on equity of 10.4 percent and a 55.0 percent equity ratio.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

2022 Wisconsin General Rate Case. In 2022, SWL&P filed a rate increase request with the PSCW seeking an average increase of 3.6 percent for retail customers. The filing sought an overall return on equity of 10.4 percent and a 55 percent equity ratio. On an annualized basis, the requested final rate increase would have generated an estimated $4.3 million in additional revenue. In an order dated December 20, 2022, the PSCW approved an annual increase of $3.3 million reflecting a return on equity of 10.0 percent and 55 percent equity ratio. Final rates went into effect January 1, 2023.

Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP, which was approved by the MPUC in an order dated January 9, 2023. The approved IRP, which reflects a joint agreement reached with various stakeholders, outlines Minnesota Power’s 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 up to 700 MW of new wind and solar energy resources, and ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. 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. Minnesota Power is expected to file its next IRP by March 1, 2025.

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, 2022, Minnesota Power submitted its 2021 consolidated filing detailing Minnesota Power’s CIP program results and proposed CIP financial incentive, which was approved by the MPUC in an order dated July 5, 2022. As a result, Minnesota Power recognized revenue of $1.9 million in 2022 for the approved CIP financial incentive ($2.4 million in 2021 and $2.4 million in 2020). CIP financial incentives are recognized in the period in which the MPUC approves the filing.

In 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 goal is $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 which is subject to various outstanding legal challenges related to the return on equity calculation and refund period ordered by the FERC. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the 2020 FERC order back to the FERC. We cannot predict the return on equity the FERC will ultimately authorize in the remanded proceeding. (See Note 6. Equity Investments.)

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 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 commenced in 2022 with a portion of these projects placed into service in the fourth quarter of 2022; the remaining project is expected to be placed into service in 2023.

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.

NOTE 4. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
As of December 31	2022	2021
Millions
Current Regulatory Assets (a)
Fuel Adjustment Clause (b)	$25.6	—
Total Current Regulatory Assets	$25.6	—
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (c)	$225.9	$226.4
Income Taxes (d)	97.6	104.7
Cost Recovery Riders (e)	41.2	63.2
Asset Retirement Obligations (f)	35.6	33.1
Manufactured Gas Plant (g)	15.1	17.0
Fuel Adjustment Clause (b)	14.5	56.4
PPACA Income Tax Deferral	4.1	4.3
Other	7.0	6.7
Total Non-Current Regulatory Assets	$441.0	$511.8
Current Regulatory Liabilities (h)
Provision for Interim Rate Refund	$18.4	—
Fuel Adjustment Clause (b)	—	$5.0
Transmission Formula Rates	4.9	3.1
Other	0.1	0.5
Total Current Regulatory Liabilities	$23.4	$8.6
Non-Current Regulatory Liabilities
Income Taxes (d)	$332.5	$353.4
Wholesale and Retail Contra AFUDC (j)	80.7	83.7
Plant Removal Obligations (k)	60.0	52.6
Defined Benefit Pension and Other Postretirement Benefit Plans (c)	17.6	28.1
North Dakota Investment Tax Credits (l)	16.9	12.2
Boswell Units 1 and 2 Net Plant and Equipment (i)	6.7	0.4
Non-Jurisdictional Land Sales (m)	7.5	—
Other	4.2	5.7
Total Non-Current Regulatory Liabilities	$526.1	$536.1

(a)Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.

(b)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.)

(c)Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, 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 12. Pension and Other Postretirement Benefit Plans.)

(d)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.

(e)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 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, 2022, will be recovered within the next two years.

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

(g)This 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.

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

(i)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.

(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.

(m)This regulatory liability represents the net proceeds from the sale of certain land by Minnesota Power that is expected to be refunded to ratepayers through a future rate case or through its renewable resources rider.

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Acquisitions

12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

2022 Activity

New Energy. On April 15, 2022, a wholly-owned subsidiary of ALLETE acquired 100 percent of the membership interests of New Energy for a purchase price of $165.5 million. Total consideration of approximately $158.8 million was paid in cash on the acquisition date, which is net of cash acquired and debt assumed. New Energy, which is headquartered in Annapolis, Maryland, is a renewable energy development company with a primary focus on solar and storage facilities while also offering comprehensive operations, maintenance and asset management services. The acquisition of New Energy is consistent with ALLETE’s stated strategy of additional investment in renewable energy and related infrastructure across North America to support the Company’s sustainability-in-action strategy while providing potential long-term earnings growth.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price, which was finalized in the fourth quarter of 2022, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis. The goodwill recorded is primarily attributable to the highly skilled workforce of New Energy and synergies expected to arise as a result of the acquisition.

Since the acquisition in April 2022, aggregate revenue was $80.2 million. The Company has not presented separate results of operations since closing or combined pro forma financial information of the Company and New Energy since the beginning of 2021, as the results of operations for New Energy are not material to the Company's consolidated financials.

Millions
Assets Acquired
Cash and Cash Equivalents	$3.9
Accounts Receivable	1.4
Inventory (a)	25.3
Other Current Assets	12.8
Property, Plant and Equipment - Net	16.4
Goodwill (b)	154.9
Other Non-Current Assets	2.1
Total Assets Acquired	$216.8
Liabilities Assumed
Current Liabilities	$23.6
Long-Term Debt Due Within One Year	28.3
Long-Term Debt	5.9
Other Non-Current Liabilities	0.2
Total Liabilities Assumed	$58.0
Net Identifiable Assets Acquired	$158.8

(a)Includes $11.6 million of purchase price accounting for certain projects under development at the time of acquisition.

(b)For tax purpose, the purchase price allocation resulted in $154.9 million of deductible goodwill.

Acquisition-related costs were $2.7 million after-tax, expensed as incurred during 2022 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

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Equity Investments

12 Months Ended

Dec. 31, 2022

Equity Method Investments and Joint Ventures [Abstract]

Equity Investments [Text Block]

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, 2023, we invested an additional $0.8 million in ATC. In total, we expect to invest approximately $8.2 million in 2023.

ALLETE’s Investment in ATC
Year Ended December 31	2022	2021
Millions
Equity Investment Beginning Balance	$154.5	$149.0
Cash Investments	5.9	—
Equity in ATC Earnings	19.3	21.3
Distributed ATC Earnings	(15.5)	(17.2)
Amortization of the Remeasurement of Deferred Income Taxes	1.2	1.4
Equity Investment Ending Balance	$165.4	$154.5

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2022	2021
Millions
Current Assets	$89.6	$89.8
Non-Current Assets	5,997.8	5,628.1
Total Assets	$6,087.4	$5,717.9
Current Liabilities	$511.9	$436.9
Long-Term Debt	2,613.0	2,513.0
Other Non-Current Liabilities	485.8	422.0
Members’ Equity	2,476.7	2,346.0
Total Liabilities and Members’ Equity	$6,087.4	$5,717.9

Income Statement Data
Year Ended December 31	2022	2021	2020
Millions
Revenue	$751.2	$754.8	$758.1
Operating Expense	381.5	376.2	372.4
Other Expense	122.9	113.9	110.9
Net Income	$246.8	$264.7	$274.8
ALLETE’s Equity in Net Income	$19.3	$21.3	$22.3

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 which is subject to various outstanding legal challenges related to the return on equity calculation and refund period ordered by the FERC. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the 2020 FERC order back to FERC. As a result of this decision, ATC recorded a reserve in the third quarter of 2022 for anticipated refunds to its customers for approximately $31 million of which our share was approximately $2.4 million pre-tax. We cannot predict the return on equity FERC will ultimately authorize in the remanded proceeding.

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.

NOTE 6. 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, 2021	$163.5
Equity in Nobles 2 Earnings (a)	(0.6)
Distributed Nobles 2 Earnings	(5.6)
Equity Investment Balance as of December 31, 2022	$157.3

(a)The Company also recorded net loss attributable to non-controlling interest of $10.6 million related to its investment in Nobles 2.

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Fair Value

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value [Text Block]

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.

NOTE 7. 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, 2022, and December 31, 2021. 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, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities	$7.7	—	—	$7.7
Available-for-sale – Corporate and Governmental Debt Securities (b)	—	$5.7	—	5.7
Cash Equivalents	4.2	—	—	4.2
Total Fair Value of Assets	$11.9	$5.7	—	$17.6
Liabilities:
Deferred Compensation (c)	—	$15.0	—	$15.0
Total Fair Value of Liabilities	—	$15.0	—	$15.0

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

(b)As of December 31, 2022, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $2.7 million, in three years to less than five years was $1.9 million and in five or more years was $0.4 million.

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

	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	—	$6.2	—	6.2
Cash Equivalents	2.5	—	—	2.5
Total Fair Value of Assets	$11.4	$6.2	—	$17.6
Liabilities: (b)
Deferred Compensation	—	$18.0	—	$18.0
Total Fair Value of Liabilities	—	$18.0	—	$18.0

(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, 2022 and 2021, 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).

NOTE 7. FAIR VALUE (Continued)

Financial Instruments	Carrying Amount	Fair Value
Millions
Short-Term and Long-Term Debt (a)
December 31, 2022	$1,929.1	$1,782.7
December 31, 2021	$1,986.4	$2,192.6

(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 $322.7 million as of December 31, 2022 ($318.0 million as of December 31, 2021). 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, 2022 and 2021, there were no indicators of impairment. (See Note 6. Equity Investments.)

Goodwill. The Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. The Company’s goodwill is a result of the New Energy acquisition in 2022. (See Note 1. Operations and Significant Accounting Policies and Note 5. Acquisitions.) The aggregate carrying amount of goodwill was $154.9 million as of December 31, 2022.

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, 2022, and 2021, 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. The MPUC order for Minnesota Power’s 2015 IRP 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. Minnesota Power’s latest IRP, which was approved by the MPUC in an order dated January 9, 2023, includes ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. Boswell Unit 3 and Unit 4 have a net book value of approximately $235 million and $435 million, respectively, as of December 31, 2022. (See Note 4. Regulatory Matters.) Minnesota Power’s latest IRP also includes the retirement of Taconite Harbor. As of December 31, 2022, Taconite Harbor had a net book value of approximately $25 million. 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.

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Short-Term and Long-Term Debt

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Short-Term and Long-Term Debt [Text Block]

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2022, total short-term debt outstanding was $272.6 million ($214.2 million as of December 31, 2021), and consisted of long-term debt due within one year and included $0.1 million of unamortized debt issuance costs.

As of December 31, 2022, we had consolidated bank lines of credit aggregating $475.7 million ($432.0 million as of December 31, 2021), most of which expire in January 2026. We had $32.8 million outstanding in standby letters of credit and $31.3 million outstanding draws under our lines of credit as of December 31, 2022 ($31.5 million in standby letters of credit and $159.7 million outstanding draws as of December 31, 2021).

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt. As of December 31, 2022, total long-term debt outstanding was $1,648.2 million ($1,763.2 million as of December 31, 2021) and included $8.2 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2023 is $91.9 million; $94.8 million in 2024; $386.1 million in 2025; $79.4 million in 2026; $122.5 million in 2027; and $1,154.4 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 February 28, 2022, ALLETE entered into an unsecured term loan agreement (February Term Loan) to borrow up to $175 million. No draws were made on the February Term Loan, which was subsequently terminated in April 2022.

On March 24, 2022, ALLETE entered into a $170 million unsecured term loan agreement (March Term Loan). The Term Loan is due March 23, 2023, and may be repaid at any time. Interest is payable monthly at a rate per annum equal to SOFR plus 0.75 percent. Proceeds from the Term Loan were used for general corporate purposes.

On August 9, 2022, ALLETE issued $75 million of its First Mortgage Bonds (Bonds) to certain institutional buyers in the private placement market. The Bonds, which bear interest at 4.54 percent, will mature in August 2032 and pay interest semi-annually in February and August of each year, commencing on February 9, 2023. 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 refinance existing indebtedness 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.

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt (Continued)

Long-Term Debt
As of December 31	2022	2021
Millions
First Mortgage Bonds
3.40% Series Due 2022	—	$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	100.0
4.54% Series Due 2032	75.0	—
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
Armenia Mountain Senior Secured Notes 3.26% Due 2024	19.3	29.1
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8	27.8
Revolving Credit Facility Variable Rate Due 2026	13.0	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 2022	—	110.0
Unsecured Term Loan Variable Rate Due 2023	170.0	—
Other Long-Term Debt, 2022 Weighted Average Rate 4.94% Due 2024 – 2051	82.0	57.5
Unamortized Debt Issuance Costs	(8.3)	(9.0)
Total Long-Term Debt	1,920.8	1,977.4
Less: Due Within One Year	272.6	214.2
Net Long-Term Debt	$1,648.2	$1,763.2

NOTE 8. 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, 2022, our ratio was approximately 0.40 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, 2022, ALLETE was in compliance with its financial covenants.

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Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

The following table details the estimated minimum payments for certain long-term commitments as of December 31, 2022:

	2023	2024	2025	2026	2027	Thereafter
Millions
Capital Purchase Obligations	$26.6	$10.6	$1.3	$2.7	—	$0.6
Easements (a)	$7.8	$7.9	$8.0	$8.1	$8.2	$206.9
PPAs (b)	$151.3	$145.8	$137.0	$136.9	$123.6	$1,010.3
Other Purchase Obligations (c)	$49.9	$10.2	$6.5	—	—	—

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

(b)Does not include 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, 2022, Square Butte had total debt outstanding of $210.2 million. Annual debt service for Square Butte is expected to be approximately $47.2 million in 2023, $32.2 million in 2024, $28.4 million in 2025, and $28.6 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.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power’s cost of power purchased from Square Butte during 2022 was $82.7 million ($82.4 million in 2021; $79.5 million in 2020). 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 $5.1 million in 2022 ($5.8 million in 2021; $7.1 million in 2020). 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, 2022:

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

(a)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.

(b)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, 2022:

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 32 percent in 2022 (28 percent in 2021 and in 2020). (See Square Butte PPA.)

(c)Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power.

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

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 2023. 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 in March 2021 revising 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. Minnesota Power will continue to monitor ongoing CSAPR rulemakings and compliance implementation, including the EPA’s Good Neighbor Rule proposed on April 6, 2022, to modify certain aspects of the CSAPR’s program scope and extent.

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. In June 2021, the EPA announced it will reconsider the December 2020 final rule retaining the 2012 particulate matter NAAQS. On January 6, 2023 the EPA announced a proposed rule to revise the primary annual particulate matter NAAQS from its current level while retaining the other primary and secondary particulate matter NAAQS. A final rule is expected by the end of 2023. The EPA also announced in October 2021 that it was reconsidering the 2020 Ozone NAAQS rule finalized in December 2020, and issued a policy assessment on April 28, 2022, recommending retention of the current standard. A proposed Ozone NAAQS rule is expected in the first half of 2023. Anticipated compliance costs related to the proposed and expected NAAQS revisions cannot yet be estimated; however, costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA Good Neighbor Plan for 2015 Ozone NAAQS. On April 6, 2022, the EPA published a proposed rule, the Good Neighbor Plan, to address regional ozone transport for the 2015 Ozone NAAQS by reducing NOx emissions during the period of May 1 through September 30 (ozone season). This rule is intended to address certain good neighbor or interstate transport provisions of the Clean Air Act relative to the 2015 Ozone NAAQS. In the justification for the proposed rule, the EPA asserted that 26 states, including Minnesota, are modeled as significant contributors to downwind states’ challenges in attaining or maintaining ozone NAAQS compliance within their state borders. The Good Neighbor Plan proposes to resolve this interstate transport issue by implementing a variety of NOx reduction strategies, including federal implementation plan requirements, NOx emission limitations, and ozone season allowance program requirements, beginning with the 2023 ozone season. The proposed rule would apply to fossil-fuel fired power plants in 25 states and certain other industrial sources in 23 states. Implementation of the rule would occur in part through changes to the existing CSAPR program.

Minnesota Power reviewed the proposed rule, assessed its potential impacts and submitted public comments to the EPA on June 21, 2022. Concerns noted by Minnesota Power and other entities included the technical accuracy of the EPA’s assumptions and methods used to identify Minnesota as a significant contributor state, as well as the proposed rule’s intended timeline. Anticipated compliance costs related to the Good Neighbor Plan cannot yet be estimated; however, the costs could be material, including costs of additional NOx controls, emission allowance program participation, or operational changes, if any are required. Minnesota Power would seek recovery of additional costs through a rate proceeding. The EPA intends to issue a final rule in early 2023, following a final action to approve or disapprove the ozone transport State Implementation Plans (SIPs). On January 31, 2023, the EPA announced its final action to partially disapprove SIPs for the states of Minnesota and Wisconsin, and to disapprove 19 other SIP submissions. The Company is currently reviewing this SIP final action and any associated costs cannot yet be anticipated until the issuance of the EPA’s final Good Neighbor Plan, which is expected in March 2023.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters (Industrial Boiler MACT) Rule. A final rule issued by the EPA for Industrial Boiler MACT became effective in 2013 with compliance required at major existing sources in 2016. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. Compliance with the Industrial Boiler MACT Rule consisted largely of adjustments to fuels and operating practices and compliance costs were not material. Subsequent to this initial rulemaking, litigation from 2016 through 2018 resulted in court orders directing that the EPA reconsider certain aspects of the regulation including the basis for and numerical value of several different emission limits. On October 6, 2022, the EPA published a final rule in the Federal Register incorporating these changes. The rule became effective on December 5, 2022, imposing a 3-year compliance deadline of October 6, 2025. Minnesota Power’s initial review of this new rule indicates that the revisions should not significantly impact the Company’s affected units. As such, compliance costs associated with the new Industrial Boiler MACT Rule are not currently expected to be material; however Minnesota Power would seek recovery of additional costs through a rate proceeding.

Climate Change. The scientific community generally accepts that emissions of GHGs 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; increased risk of wildfires; 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.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 from 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, Hibbard Units 3 and 4, and Taconite Harbor Units 1 and 2; Taconite Harbor Units 1 and 2 are currently economically idled.

In January 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 for review of the D.C. Circuit’s opinion were subsequently granted by the U.S. Supreme Court in October 2021, consolidated under West Virginia v. EPA et al. On June 30, 2022, the U.S. Supreme Court released its opinion in favor of West Virginia and aligned parties. The Supreme Court found the EPA’s CPP structure of generation shifting to be disallowed under Section 111(d) of the CCA on grounds of the major questions doctrine. The court did not opine upon the regulatory approach the EPA proposed in the Affordable Clean Energy Rule. The petitions were remanded to the D.C. Circuit. The EPA has indicated that it intends to issue a proposed rule in early 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.

In April 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.

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.

Additionally in January 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. Currently, the EPA is a performing a comprehensive review of the Section 111(b) GHG NSPS for electric generating units, with a notice of proposed rulemaking expected in early 2023. Minnesota Power is monitoring the NSPS final rule and any further Section 111(b) developments including their potential impact to the Company. The proposed combined-cycle natural gas-fired generating facility, NTEC, is expected to meet these NSPS requirements.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 (BATW) 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 its 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 2023.

Under the 2020 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 will either need to be re-used in a closed-loop process or routed to a FGD scrubber. FGD wastewater is required to meet stringent water quality standards for discharge to surface water.

Bottom ash transport and FGD wastewater ELG’s are not currently expected to have a significant impact on Minnesota Power operations. Boswell Energy Center, where ELG’s are primarily applicable, completed conversion to dry bottom ash handling and installed a FGD dewatering system in September 2022. The dry conversion projects eliminated bottom ash transport water and minimized wastewater from the FGD system. Re-use and onsite consumption is planned for the remaining FGD waste stream and for dewatering legacy wastewater from Boswell’s existing impoundments. Water re-use and consumption activities are expected to eliminate the need for surface water discharges prior to the current ELG Rule deadline of December 31, 2025.

The EPA’s additional reconsideration of legacy wastewater and leachate discharge requirements has the potential to impact leachate discharges associated with the closed impoundment at the Laskin and Taconite Harbor Energy Centers Dry Ash Landfill. In its spring 2022 Unified Agenda, the EPA announced it intends to consolidate consideration of legacy wastewater and leachate with the ELG/FGD and BATW proposed rulemaking currently expected in 2023. It is unknown at this time if the rule revisions will include new requirements for these waste streams.

At this time, we estimate no additional material compliance costs for ELG bottom ash water and FGD requirements. Compliance costs we might incur related to other ELG waste streams (e.g., leachate) or other potential future water discharge regulations at Minnesota Power facilities 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.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 transmitted a final list of 32 EPA-added wild rice waters to the MPCA in November 2021. This list 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 (2015 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. Minnesota Power sought EPA approval under the Part A Rule to extend the closure date for two active Boswell impoundments in November 2020. Upon completion of dry ash conversion activities, Boswell ceased disposal in both impoundments on September 17, 2022 and formally withdrew the CCR Part A Application. The EPA acknowledged the Part A variance application withdrawal on September 20, 2022, and indicated that no further EPA review of Boswell’s Part A variance application will occur. Both impoundments are now inactive and have initiated closure.

Additionally, the EPA released a proposed Part B rulemaking in February 2020 addressing 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 updated fall 2022 regulatory agenda, finalization of the remainder of the proposed Part B Rule is expected in late 2023. Two additional rulemakings are also expected in mid-2023, the proposed Legacy Impoundment Rule and the Final Federal Permit Rule. The Legacy Impoundment Rule will include a revised definition for legacy CCR Impoundments which could regulate impoundments that had closed prior to the effective date of the 2015 Rule. The Final Federal Permit Rule will finalize procedures for implementing a CCR Federal Permit Program. Expected compliance costs at Boswell due to the 2018 court decision and subsequent rule revisions are reflected in our estimate of compliance costs for the CCR rule noted previously.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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, 2022, we have recorded a liability of $14.9 million for remediation costs at this site. SWL&P has recorded the site as an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. The majority of remediation costs are expected to be incurred through 2023.

Commitments Contingencies and Guarantees

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, 2022, we had $290.3 million of outstanding letters of credit issued, including those issued under our revolving credit facility.

Regulated Operations. As of December 31, 2022, we had $28.2 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 is party to PSAs that expire in various years between 2024 and 2039. As of December 31, 2022, ALLETE Clean Energy has $222.3 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, 2022, BNI Energy had surety bonds outstanding of $82.4 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 $82.1 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, 2022, ALLETE South Wind has $11.7 million outstanding in standby letters of credit, related to our portion of the security requirements relative to our ownership in Nobles 2.

New Energy. As of December 31, 2022, New Energy had $4.2 million outstanding in standby letters of credit pledged as security in connection with the acquisition of solar equipment for projects under development. New Energy does not believe it is likely that any of these outstanding letters of credit will be drawn upon.

South Shore Energy. As of December 31, 2022, 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, 2022, 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.

NOTE 9. 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, 2022, we owned 42 percent of the assessable land in the Town Center District (30 percent as of December 31, 2021). As of December 31, 2022, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $1.3 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.

XML

Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Common Stock and Earnings Per Share [Text Block]

COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2019	51,679	$1,436.7
Employee Stock Purchase Plan	13	0.7
Invest Direct	309	18.3
Share-Based Compensation	84	5.2
Balance as of December 31, 2020	52,085	1,460.9
Employee Stock Purchase Plan	17	0.8
Invest Direct	263	17.5
Share-Based Compensation	73	6.5
Equity Issuance Program	782	51.0
Balance as of December 31, 2021	53,220	1,536.7
Employee Stock Purchase Plan	11	0.9
Invest Direct	244	14.9
Share-Based Compensation	82	5.3
Equity Issuance	3,680	223.7
Balance as of December 31, 2022	57,237	$1,781.5

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, 2022. For the year ended December 31, 2022, no shares of common stock were issued under this agreement (0.8 million shares for net proceeds of $51.0 million in 2021; none in 2020) .

On April 5, 2022, ALLETE issued and sold approximately 3.7 million shares of ALLETE common stock. Net proceeds of approximately $224 million were received from the sale of shares. Proceeds were used primarily to fund the acquisition of New Energy and capital investments at ALLETE Clean Energy.

NOTE 10. COMMON STOCK AND EARNINGS PER SHARE (Continued)

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
2022
Net Income Attributable to ALLETE	$189.3		$189.3
Average Common Shares	55.9	0.1	56.0
Earnings Per Share	$3.38		$3.38
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	$165.4		$165.4
Average Common Shares	51.9	—	51.9
Earnings Per Share	$3.18		$3.18

XML

Income Tax Expense

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE

Income Tax Expense
Year Ended December 31	2022	2021	2020
Millions
Current Income Tax Expense (a)
Federal	$1.2	—	—
State	6.1	—	—
Total Current Income Tax Expense	$7.3	—	—
Deferred Income Tax Expense (Benefit)
Federal (b)	$(32.8)	$(37.2)	$(51.5)
State (c)	(5.2)	10.8	8.6
Investment Tax Credit Amortization	(0.5)	(0.5)	(0.5)
Total Deferred Income Tax Expense (Benefit)	$(38.5)	$(26.9)	$(43.4)
Total Income Tax Expense (Benefit)	$(31.2)	$(26.9)	$(43.4)

(a)For the years ended December 31, 2021 and 2020, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of certain tax legislation. Federal and state NOLs are being carried forward to offset current and future taxable income. For the year ended December 31, 2022, federal NOLs were fully utilized and production tax credits were used to partially offset federal taxable income.

(b)For the years ended December 31, 2022, 2021 and 2020, the federal tax benefit is primarily due to production tax credits.

(c)For the year ended December 31, 2022, the state impact includes the benefit of deferred repricing as a result of the New Energy acquisition.

NOTE 11. INCOME TAX EXPENSE (Continued)

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2022		2021		2020
Millions
Income Before Non-Controlling Interest and Income Taxes	$100.1		$110.9		$109.4
Statutory Federal Income Tax Rate	21	%	21	%	21	%
Income Taxes Computed at Statutory Federal Rate	$21.0		$23.3		$23.0
Increase (Decrease) in Tax Due to:
State Income Taxes	8.6		8.6		6.5
Deferred Income Tax Revaluation	(7.9)		—		—
Production Tax Credits	(50.7)		(53.5)		(62.7)
Investment Tax Credits	(4.1)		—		—
Regulatory Differences – Excess Deferred Tax Benefit (a)	(9.1)		(9.5)		(9.9)
Non-Controlling Interest	11.2		6.3		2.7
AFUDC - Equity	(1.1)		(1.0)		(0.8)
Other	0.9		(1.1)		(2.2)
Total Income Tax Benefit	$(31.2)		$(26.9)		$(43.4)

(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 31.2 percent for 2022 (benefit of 24.3 percent for 2021; benefit of 39.7 percent for 2020). The 2022 and 2021 effective tax rates were primarily impacted by production tax credits and non-controlling interests in subsidiaries. The 2020 effective tax rate was primarily impacted by production tax credits.

Deferred Income Tax Assets and Liabilities
As of December 31	2022	2021
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation	$46.4	$44.5
Property-Related	61.9	54.8
NOL Carryforwards	16.7	67.5
Capital Loss Carryforwards	13.1	—
Tax Credit Carryforwards	548.7	509.1
Power Sales Agreements	13.7	16.5
Regulatory Liabilities	95.5	101.5
Other	28.1	18.0
Gross Deferred Income Tax Assets	824.1	811.9
Deferred Income Tax Asset Valuation Allowance	(60.2)	(69.0)
Total Deferred Income Tax Assets	$763.9	$742.9
Deferred Income Tax Liabilities
Deferred Gain	$7.9	$7.9
Property-Related	661.7	680.8
Regulatory Asset for Benefit Obligations	57.7	54.9
Unamortized Investment Tax Credits	30.0	30.5
Partnership Basis Differences	126.0	106.3
Fuel Adjustment Clause	10.7	14.3
Regulatory Assets	28.0	30.0
Total Deferred Income Tax Liabilities	$922.0	$924.7
Net Deferred Income Taxes (a)	$158.1	$181.8

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

NOTE 11. INCOME TAX EXPENSE (Continued)

NOL and Tax Credit Carryforwards
As of December 31	2022	2021
Millions
Federal NOL Carryforwards (a)	—	$177.3
Federal Tax Credit Carryforwards	$464.5	$416.4
Federal Capital Loss (a)	$35.1	—
State NOL Carryforwards (a)	$323.0	$506.9
State Tax Credit Carryforwards (b)	$24.5	$24.2
State Capital Loss (a)	$83.2	—

(a)Pre-tax amounts.

(b)Net of a $59.6 million valuation allowance as of December 31, 2022 ($68.6 million as of December 31, 2021).

The federal NOL, capital loss and tax credit carryforward periods expire between 2026 and 2043. We expect to fully utilize the federal NOL, capital loss and tax credit carryforwards; therefore, no federal valuation allowance has been recognized as of December 31, 2022. The pre-apportioned state NOL, capital loss and tax credit carryforward periods expire between 2023 and 2046. We have established a valuation allowance against certain state NOL, capital loss and tax credits that we do not expect to utilize before their expiration.

Gross Unrecognized Income Tax Benefits	2022	2021	2020
Millions
Balance at January 1	$1.3	$1.4	$1.4
Additions for Tax Positions Related to the Current Year	—	—	0.1
Reductions for Tax Positions Related to Prior Years	—	(0.1)	(0.1)
Balance as of December 31	$1.3	$1.3	$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, 2022, included $0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2022, we had immaterial accrued interest (none as of December 31, 2021, and 2020) 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 2022, 2021 and 2020. There were no penalties recognized in 2022, 2021 or 2020. The unrecognized tax benefit amounts have been presented as an increase to the net deferred tax liability 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 is currently under examination by the state of Wisconsin for the tax years 2018 through 2020. ALLETE has no open federal audits, and is no longer subject to federal examination for years before 2019 or state examination for years before 2018. Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns.

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Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

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 2016. The plans provide defined benefits based on years of service and final average pay. We made no contributions to the plan trusts in 2022 ($10.3 million in 2021; $10.7 million in 2020). We also have a defined contribution RSOP covering substantially all employees. The 2022 plan year employer contributions totaled $12.0 million ($11.5 million for the 2021 plan year; $11.2 million for the 2020 plan year). (See Note 10. Common Stock and Earnings Per Share and Note 13. 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 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 2015, and in 2018, the postretirement life plan was amended to limit the benefit level for union employees retiring after December 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 2022, no contributions were made to the VEBAs (none in 2021; none in 2020) and no contributions were made to the grantor trusts (none in 2021; none in 2020).

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. On January 17, 2023, we contributed $6.5 million in cash to the defined benefit pension plans. We do not expect to make any further contributions to the defined benefit pension plans in 2023, and we do not expect to make any contributions to the defined benefit postretirement health and life plans in 2023.

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.

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
As of December 31	2022	2021
Millions
Accumulated Benefit Obligation	$724.5	$875.5
Change in Benefit Obligation
Obligation, Beginning of Year	$911.7	$965.7
Service Cost	9.3	11.0
Interest Cost	27.2	24.6
Plan Amendments	0.8	—
Plan Curtailments	—	(1.4)
Actuarial Gain (a)	(160.6)	(39.0)
Benefits Paid	(58.9)	(56.5)
Participant Contributions	10.2	7.3
Obligation, End of Year	$739.7	$911.7
Change in Plan Assets
Fair Value, Beginning of Year	$745.7	$759.4
Actual Return on Plan Assets	(130.5)	23.1
Employer Contribution (b)	12.3	19.7
Benefits Paid	(58.9)	(56.5)
Fair Value, End of Year	$568.6	$745.7
Funded Status, End of Year	$(171.1)	$(166.0)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(2.1)	$(2.1)
Non-Current Liabilities (c)	$(169.0)	$(163.9)

(a)    Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

(b)    Includes Participant Contributions noted above, any contributions made by the Company to pension plan trusts and any direct benefit payments made under certain plans.

(c)    Presented here net of amounts related to prepaid pension for SWL&P that are reclassified to Regulatory Assets on the Consolidated Balance Sheet.

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 $0.1 million as of December 31, 2022 (net loss of $260.2 million and prior service credit of $1.0 million as of December 31, 2021).

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2022	2021
Millions
Net Loss	$(260.2)	$(260.2)
Prior Service Credit	0.1	1.0
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	89.0	93.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(171.1)	$(166.0)

Components of Net Periodic Pension Cost
Year Ended December 31	2022	2021	2020
Millions
Service Cost	$9.3	$11.0	$10.7
Non-Service Cost Components (a)
Interest Cost	27.2	24.6	27.9
Expected Return on Plan Assets	(41.5)	(43.4)	(42.7)
Amortization of Loss	11.4	18.8	12.8
Amortization of Prior Service Credit	(0.1)	(0.2)	(0.2)
Net Pension Cost	$6.3	$10.8	$8.5

(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	2022	2021
Millions
Net (Gain) Loss	$11.4	$(20.1)
Amortization of Prior Service Credit	0.1	0.2
Prior Service Credit Arising During the Period	0.8	—
Amortization of Loss	(11.4)	(18.8)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$0.9	$(38.7)

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2022	2021
Millions
Projected Benefit Obligation	$739.7	$911.7
Accumulated Benefit Obligation	$724.5	$875.5
Fair Value of Plan Assets	$568.6	$745.7

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Postretirement Health and Life Obligation and Funded Status
As of December 31	2022	2021
Millions
Change in Benefit Obligation
Obligation, Beginning of Year	$148.2	$167.6
Service Cost	3.0	3.6
Interest Cost	4.4	4.4
Actuarial Gain (a)	(38.7)	(19.7)
Benefits Paid	(9.2)	(10.6)
Participant Contributions	2.7	2.9
Obligation, End of Year	$110.4	$148.2
Change in Plan Assets
Fair Value, Beginning of Year	$201.8	$186.0
Actual Return on Plan Assets	(33.0)	22.8
Employer Contribution	0.3	0.7
Participant Contributions	2.7	2.9
Benefits Paid	(9.2)	(10.6)
Fair Value, End of Year	$162.6	$201.8
Funded Status, End of Year	$52.2	$53.6
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$58.8	$64.8
Current Liabilities	$(0.2)	$(1.4)
Non-Current Liabilities	$(6.4)	$(9.8)

(a)Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

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 $11.8 million in irrevocable grantor trusts included in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2022 ($13.2 million as of December 31, 2021).

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	2022	2021
Millions
Net Gain	$(9.2)	$(12.7)
Prior Service Credit	(13.2)	(20.7)
Total Unrecognized Postretirement Health and Life Cost	$(22.4)	$(33.4)

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2022	2021
Millions
Net Gain (a)	$9.2	$12.7
Prior Service Credit	13.2	20.7
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	29.8	20.2
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$52.2	$53.6

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

Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2022	2021	2020
Millions
Service Cost	$3.0	$3.6	$3.3
Non-Service Cost Components (a)
Interest Cost	4.4	4.4	5.0
Expected Return on Plan Assets	(9.6)	(9.9)	(9.7)
Amortization of Loss	0.4	3.0	1.0
Amortization of Prior Service Credit	(7.5)	(7.6)	(8.0)
Effect of Plan Curtailment	—	—	(0.3)
Net Postretirement Health and Life Credit	$(9.3)	$(6.5)	$(8.7)

(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	2022	2021
Millions
Net (Gain) Loss	$3.9	$(32.7)
Amortization of Prior Service Credit	7.5	7.6
Amortization of Loss	(0.4)	(3.0)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$11.0	$(28.1)

Estimated Future Benefit Payments	Pension	Postretirement Health and Life
Millions
2023	$58.0	$7.2
2024	$58.4	$7.5
2025	$58.0	$7.5
2026	$57.3	$7.7
2027	$57.0	$8.0
Years 2028 – 2032	$274.9	$42.4

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Weighted Average Assumptions Used to Determine Benefit Obligation
As of December 31	2022	2021
Discount Rate
Pension	5.70%	3.05%
Postretirement Health and Life	5.68%	3.09%
Rate of Compensation Increase	3.58%	3.58%
Health Care Trend Rates
Trend Rate	6.50%	5.66%
Ultimate Trend Rate	5.00%	4.50%
Year Ultimate Trend Rate Effective	2038	2038

Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2022	2021	2020
Discount Rate
Pension	3.28%	2.87%	3.52%
Postretirement Health and Life	3.09%	2.70%	3.45%
Expected Long-Term Return on Plan Assets
Pension	6.00%	6.50%	6.75%
Postretirement Health and Life	5.41%	5.85%	6.08%
Rate of Compensation Increase	3.58%	3.62%	4.06%

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, 2022, considered a modified PRI-2012 mortality table and MP-2021 mortality projection scale.

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Actual Plan Asset Allocations	Pension		Postretirement Health and Life (a)
	2022	2021	2022	2021
Equity Securities	46%	49%	66%	70%
Fixed Income Securities	50%	48%	34%	29%
Private Equity	—	—	—	1%
Real Estate	4%	3%	—	—
	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, 2022 (no shares as of December 31, 2021).

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, 2022:

Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	49	%	65	%
Fixed Income Securities	50	%	35	%
Real Estate	1	%	—
	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 7. Fair Value.)

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Pension Fair Value

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—	$61.2	—	$61.2
U.S. Mid-cap Growth (a)	—	40.0	—	40.0
U.S. Small-cap (a)	—	35.4	—	35.4
International	$127.0	—	—	127.0
Fixed Income Securities (a)	—	275.3	—	275.3
Cash and Cash Equivalents	7.3	—	—	7.3
Real Estate	—	—	$22.4	22.4
Total Fair Value of Assets	$134.3	$411.9	$22.4	$568.6

(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	Real Estate
Millions
Balance as of December 31, 2021	$21.6
Actual Return on Plan Assets	1.0
Purchases, Sales, and Settlements – Net	(0.2)
Balance as of December 31, 2022	$22.4

	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
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.

NOTE 12. 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, 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

Postretirement Health and Life Fair Value

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap	$26.7	—	—	$26.7
U.S. Mid-cap Growth	25.5	—	—	25.5
U.S. Small-cap	12.7	—	—	12.7
International	41.5	—	—	41.5
Fixed Income Securities:
Mutual Funds	55.5	—	—	55.5
Cash and Cash Equivalents	0.7	—	—	0.7
Total Fair Value of Assets	$162.6	—	—	$162.6

(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, 2021	$2.0
Actual Return on Plan Assets	(1.5)
Purchases, Sales, and Settlements – Net	(0.5)
Balance as of December 31, 2022	—

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

	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

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.

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Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement [Abstract]

Employee Stock and Incentive Plans [Text Block]

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 $12.0 million in 2022 ($11.5 million in 2021; $11.2 million in 2020).

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, 2022, 2021 and 2020.

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 0.8 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.6 million of these shares remain available for issuance as of December 31, 2022.

NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

The following types of share-based awards were outstanding in 2022, 2021 or 2020:

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	2022	2021	2020
Millions
Performance Shares	$0.7	$2.0	$2.2
Restricted Stock Units	0.9	1.0	0.9
Total Share-Based Compensation Expense	$1.6	$3.0	$3.1
Income Tax Benefit	$0.5	$0.9	$0.9

There were no capitalized share-based compensation costs during the years ended December 31, 2022, 2021 or 2020.

As of December 31, 2022, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $1.9 million and $0.8 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years and 1.6 years, respectively.

NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

Performance Shares. The following table presents information regarding our non-vested performance shares.

	2022		2021		2020
	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	80,661	$75.80	85,284	$80.73	99,585	$72.78
Granted (a)	37,731	$67.22	33,304	$73.25	25,763	$83.17
Awarded	—	—	—	—	(25,304)	$62.03
Unearned Grant Award	(50,524)	$77.49	(33,375)	$86.09	(13,625)	$62.03
Forfeited	(7,379)	$71.00	(4,552)	$74.05	(1,135)	$79.81
Non-vested as of December 31	60,489	$69.62	80,661	$75.80	85,284	$80.73

(a)    Shares granted include accrued dividends.

There were approximately 51,000 performance shares granted in February 2023 for the three-year performance period ending in 2025. 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 $3.4 million. There were no performance shares awarded in February 2023.

Restricted Stock Units. The following table presents information regarding our available restricted stock units.

	2022		2021		2020
	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	28,141	$73.16	37,482	$77.64	39,943	$69.30
Granted (a)	15,477	$63.70	16,251	$64.97	15,169	$83.48
Awarded	(7,396)	$75.55	(23,631)	$74.53	(17,193)	$63.41
Forfeited	(2,658)	$66.44	(1,961)	$74.52	(437)	$77.52
Available as of December 31	33,564	$68.80	28,141	$73.16	37,482	$77.64

(a)    Shares granted include accrued dividends.

There were approximately 14,700 restricted stock units granted in February 2023 for the vesting period ending in 2025. The grant date fair value of the restricted stock units granted was $0.9 million. There were approximately 8,500 restricted stock units awarded in February 2023. The grant date fair value of the shares awarded was $0.7 million.

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Business Segments

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

BUSINESS SEGMENTS

We present two reportable segments: Regulated Operations and ALLETE Clean Energy. 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. We also present Corporate and Other which includes three operating segments, New Energy, a renewable energy development company, 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, land holdings in Minnesota, and earnings on cash and investments.

NOTE 14. BUSINESS SEGMENTS (Continued)

Year Ended December 31	2022	2021	2020
Millions
Operating Revenue
Residential	$175.9	$160.8	$140.7
Commercial	187.2	168.6	139.5
Municipal	40.2	52.0	41.2
Industrial	589.0	565.5	432.8
Other Power Suppliers	165.8	168.7	138.8
Other	101.2	112.3	94.3
Total Regulated Operations	1,259.3	1,227.9	987.3
ALLETE Clean Energy
Long-term PSA	77.2	75.5	68.3
Sale of Wind Energy Facility	33.5	—	—
Other	7.6	11.4	11.3
Total ALLETE Clean Energy	118.3	86.9	79.6
Corporate and Other
Long-term Contract	89.2	84.4	86.0
Sale of Renewable Development Projects	73.9	—	—
Other	30.0	20.0	16.2
Total Corporate and Other	193.1	104.4	102.2
Total Operating Revenue	$1,570.7	$1,419.2	$1,169.1
Net Income Attributable to ALLETE (a)
Regulated Operations	$149.9	$129.1	$136.3
ALLETE Clean Energy	16.3	26.3	21.1
Corporate and Other (b)(c)	23.1	13.8	8.0
Total Net Income Attributable to ALLETE	$189.3	$169.2	$165.4

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. 

(b)    Net Income in 2022 includes a $8.3 million after-tax expense as a result of purchase price accounting related to projects under development at the time of acquisition and $2.7 million after-tax of transaction costs related to the acquisition of New Energy.

(c)    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.)

NOTE 14. BUSINESS SEGMENTS (Continued)

Year Ended December 31	2022	2021	2020
Millions
Depreciation and Amortization
Regulated Operations	$171.9	$170.7	$166.9
ALLETE Clean Energy	58.6	49.2	37.9
Corporate and Other	11.7	11.8	13.0
Total Depreciation and Amortization	$242.2	$231.7	$217.8
Impairment of Property, Plant and Equipment
ALLETE Clean Energy	—	—	$12.7
Interest Expense (a)
Regulated Operations	$58.1	$57.3	$58.5
ALLETE Clean Energy	2.3	1.5	2.2
Corporate and Other	19.6	13.2	13.2
Eliminations	(4.8)	(2.9)	(8.3)
Total Interest Expense	$75.2	$69.1	$65.6
Equity Earnings
Regulated Operations	$19.3	$21.3	$22.3
Corporate and Other	(0.6)	(1.3)	(0.2)
Total Equity Earnings	$18.7	$20.0	$22.1
Income Tax Expense (Benefit)
Regulated Operations	$(10.4)	$(16.6)	$(19.4)
ALLETE Clean Energy	(15.4)	(16.6)	(23.0)
Corporate and Other	(5.4)	6.3	(1.0)
Total Income Tax Benefit	$(31.2)	$(26.9)	$(43.4)

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.    

As of December 31	2022	2021
Millions
Assets
Regulated Operations	$4,291.4	$4,289.4
ALLETE Clean Energy	1,873.3	1,706.7
Corporate and Other	680.9	426.2
Total Assets	$6,845.6	$6,422.3
Capital Expenditures
Regulated Operations	$158.3	$166.8
ALLETE Clean Energy	2.2	269.9
Corporate and Other	47.6	39.7
Total Capital Expenditures	$208.1	$476.4

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2022

Selected Quarterly Financial Information [Abstract]

Quarterly Financial Data (Unaudited) [Text Block]

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
2022
Operating Revenue	$383.5	$373.1	$388.3	$425.8
Operating Income	$53.4	$13.7	$33.4	$33.7
Net Income Attributable to ALLETE	$66.3	$37.6	$33.7	$51.7
Earnings Per Share of Common Stock
Basic	$1.24	$0.67	$0.59	$0.90
Diluted	$1.24	$0.67	$0.59	$0.90
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 (a)
Operating Revenue	$311.6	$243.2	$293.9	$320.4
Operating Income	$60.2	$12.7	$41.6	$23.7
Net Income Attributable to ALLETE	$66.3	$20.1	$40.7	$38.3
Earnings Per Share of Common Stock
Basic	$1.28	$0.39	$0.78	$0.74
Diluted	$1.28	$0.39	$0.78	$0.73

(a)    See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

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Schedule II

12 Months Ended

Dec. 31, 2022

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II [Text Block]

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
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	—	—	—	—	—
2022 Trade Accounts Receivable	$1.8	$1.9	—	$2.1	$1.6
Finance Receivables – Long-Term	—	—	—	—	—
Deferred Asset Valuation Allowance
2020 Deferred Tax Assets	$70.0	$(0.1)	—	—	$69.9
2021 Deferred Tax Assets	$69.9	$(0.9)	—	—	$69.0
2022 Deferred Tax Assets	$69.0	$(8.8)	—	—	$60.2

(a)    Includes uncollectible accounts written-off.

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Operations and Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Financial Statement Preparation [Policy Text Block]

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. The presentation of certain prior period amounts on the Consolidated Financial Statements have been adjusted for comparative purposes.

Subsequent Events [Policy Text Block]

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

Principles of Consolidation [Policy Text Block]

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 [Policy Text Block]

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 [Policy Text Block]

We present two reportable segments: Regulated Operations and ALLETE Clean Energy. 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. We present two reportable segments: Regulated Operations and ALLETE Clean Energy. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Cash and Cash Equivalents [Policy Text Block]

We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Accounts Receivable [Policy Text Block]

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.

Long-Term Finance Receivables [Policy Text Block]

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 [Policy Text Block]

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 [Policy Text Block]

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.

Property, Plant and Equipment [Policy Text Block]

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. The MPUC order for Minnesota Power’s 2015 IRP 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. Minnesota Power’s latest IRP, which was approved by the MPUC in an order dated January 9, 2023, includes ceasing coal operations at Boswell Units 3 and 4 by 2030 and 2035, respectively. Boswell Unit 3 and Unit 4 have a net book value of approximately $235 million and $435 million, respectively, as of December 31, 2022. (See Note 4. Regulatory Matters.) Minnesota Power’s latest IRP also includes the retirement of Taconite Harbor. As of December 31, 2022, Taconite Harbor had a net book value of approximately $25 million. 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 [Policy Text Block]

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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Derivatives [Policy Text Block]

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 [Policy Text Block]

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 13. Employee Stock and Incentive Plans.)

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.

Short-term Leases [Policy Text Block]

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.

Environmental Liabilities [Policy Text Block]

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.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.

Leases [Policy Text Block]

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.

Revenue Recognition [Policy Text Block]

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.

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 14 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. One of these 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 expiring in 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 52 percent of total regulated utility kWh sales for the year ended December 31, 2022. Within industrial revenue, Minnesota Power had seven Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2022. These contracts automatically renew past the contract term unless a four-year written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2026 through 2029. 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 $55 million per annum through 2026, $15 million in 2027, and $25 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.

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 2024 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.

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.

Sale of Renewable Development Projects includes revenue recognized from development only and development plus construction type projects that are sold to a customer. For development only projects, revenue is recognized at point in time when all required development responsibilities have been completed and ownership has transferred to the customer. For development plus construction, the transaction price is allocated to two performance obligations based upon the standalone selling price of each obligation. Revenue is recognized on the development performance obligation upon satisfying all required development activities and ownership transferring to the customer. Revenue for the construction performance obligation is recognized over time based on construction costs incurred, beginning at notice to proceed through the commercial operation date.

Other primarily includes revenue from BNI Energy unrelated to coal, revenue from New Energy for asset management services and non-development activities, 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.

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, 2022, we have $21.0 million of assets recognized for costs incurred to obtain contracts with our customers ($23.3 million as of December 31, 2021). 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 $2.4 million of non-cash amortization for the year ended December 31, 2022 ($2.7 million for the year end December 31, 2021).

Revenue from CIP Financial Incentive [Policy Text Block]

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.

Unamortized Discount and Premium on Debt [Policy Text Block]

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.

Non-Controlling Interest in Subsidiaries [Policy Text Block]

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.

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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Income Taxes [Policy Text Block]

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. We account for the collection and payment of these taxes on a net basis.We have established a valuation allowance against certain state NOL, capital loss and tax credits that we do not expect to utilize before their expiration.

Unrecognized Tax Benefits [Policy Text Block]

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.We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income.The unrecognized tax benefit amounts have been presented as an increase to the net deferred tax liability on the Consolidated Balance Sheet.

Excise Taxes [Policy Text Block]

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.

Depreciation [Policy Text Block]

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

Asset Retirement Obligations [Policy Text Block]

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.

Regulatory Assets and Liabilities [Policy Text Block]

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.

Equity Method Investments [Policy Text Block]

We account for our investment in ATC under the equity method of accounting.We account for our investment in Nobles 2 under the equity method of accounting.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.

Fair Value Measurement [Policy Text Block]

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.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.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.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 7. Fair Value.)

Fair Value Transfers [Policy Text Block]

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.

Property, Plant and Equipment Impairment [Policy Text Block]

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.

Pension and Other Postretirement Benefit Plans [Policy Text Block]

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

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.

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)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 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.

Employee Stock Ownership Plan [Policy Text Block]

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.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, 2022, 2021 and 2020.

Goodwill and Intangible Assets, Goodwill, Policy

Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. Goodwill is assessed annually in the fourth quarter for impairment and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level.

Business Combinations Policy

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price, which was finalized in the fourth quarter of 2022, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.

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Regulated Operations (Policies)	12 Months Ended
	Dec. 31, 2022
Regulated Operations [Abstract]
Regulatory Assets and Liabilities [Policy Text Block]	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.
Recognition of Regulatory Outcomes Policy	Impacts of regulatory outcomes that are determined subsequent to the balance sheet date, and prior to issuance of the financial statements, are recognized in the financial statements as of the balance sheet date.

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Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Cash, Cash Equivalents and Restricted Cash [Table Text Block]

Cash, Cash Equivalents and Restricted Cash
As of December 31	2022	2021	2020
Millions
Cash and Cash Equivalents	$36.4	$45.1	$44.3
Restricted Cash included in Prepayments and Other	1.5	0.3	0.8
Restricted Cash included in Other Non-Current Assets	2.3	2.3	20.1
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows	$40.2	$47.7	$65.2

Supplemental Statement of Cash Flow Information [Table Text Block]

Supplemental Statement of Cash Flow Information.

Consolidated Statement of Cash Flows
Year Ended December 31	2022	2021	2020
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$72.8	$66.8	$62.0
Cash Paid (Received) for Income Taxes	$6.0	—	$(2.0)
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(9.6)	$(14.0)	$(67.0)
Reclassification of Property, Plant and Equipment to Inventory (a)	$99.7	—	—
Reclassification of Redeemable Non-Controlling Interest to Current Liabilities (b)	—	$30.6	—
Capitalized Asset Retirement Costs	$11.8	$16.9	$4.1
AFUDC–Equity	$2.7	$2.6	$1.9

(a)The decommissioning of the existing Northern Wind assets resulted in a reclassification from Property, Plant and Equipment – Net to Inventories – Net in the second quarter of 2022 as they were repowered and subsequently sold to a subsidiary of Xcel Energy Inc. In the third quarter of 2022, safe harbor equipment was transferred to the project entity resulting in an additional reclassification from Property, Plant and Equipment – Net to Inventories – Net.

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

Accounts Receivable [Table Text Block]

Accounts Receivable
As of December 31	2022	2021
Millions
Trade Accounts Receivable
Billed	$107.1	$100.6
Unbilled	29.2	24.7
Less: Allowance for Doubtful Accounts	1.6	1.8
Total Trade Accounts Receivable	134.7	123.5
Income Taxes Receivable	3.2	0.2
Total Accounts Receivable	$137.9	$123.7

Inventories – Net [Table Text Block]

Inventories – Net
As of December 31	2022	2021
Millions
Fuel (a)	$33.4	$18.7
Materials and Supplies	75.1	56.1
Construction of Wind Energy Facilities (b)	347.4	22.9
Total Inventories – Net	$455.9	$97.7

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

(b) Project costs related to ALLETE Clean Energy’s Northern Wind project sold in January 2023 and Red Barn wind project which is expected to be sold in the first half 2023. (See Other Current Liabilities.)

Other Non-Current Assets [Table Text Block]

Other Non-Current Assets
As of December 31	2022	2021
Millions
Contract Assets (a)	$21.0	$23.3
Operating Lease Right-of-use Assets	12.7	16.4
ALLETE Properties	19.1	19.4
Restricted Cash	2.3	2.3
Other Postretirement Benefit Plans	58.8	64.8
Other	90.4	86.7
Total Other Non-Current Assets	$204.3	$212.9

(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 [Table Text Block]

Other Current Liabilities
As of December 31	2022	2021
Millions
Customer Deposits (a)	$150.7	$27.2
PSAs	6.1	12.6
Provision for Interim Rate Refund	18.4	—
Manufactured Gas Plant (b)	14.7	12.8
Fuel Adjustment Clause	—	5.0
Operating Lease Liabilities	3.2	4.8
Redeemable Non-Controlling Interest (c)	—	30.6
Other	57.9	40.0
Total Other Current Liabilities	$251.0	$133.0

(a)    Primarily related to deposits received by ALLETE Clean Energy for the Northern Wind project sold in January 2023 and the Red Barn wind project which is expected to be sold in the first half of 2023. (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 9. 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 [Table Text Block]

Other Non-Current Liabilities
As of December 31	2022	2021
Millions
Asset Retirement Obligation (a)	$200.4	$184.5
PSAs	26.9	39.5
Operating Lease Liabilities	9.3	11.6
Other	32.4	45.2
Total Other Non-Current Liabilities	$269.0	$280.8

(a) The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $32.4 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2022 ($28.5 million as of December 31, 2021).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Lease, Cost [Table Text Block]

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

As December 31	2022	2021
Millions
Operating Lease Cost	$6.3	$6.7
Other Information:
Operating Cash Flows From Operating Leases	$6.3	$6.7

Additional information related to leases was as follows:

As of December 31	2022		2021
Millions
Balance Sheet Information Related to Leases:
Other Non-Current Assets	$12.7		$16.4
Total Operating Lease Right-of-use Assets	$12.7		$16.4
Other Current Liabilities	$3.2		$4.8
Other Non-Current Liabilities	9.3		11.6
Total Operating Lease Liabilities	$12.5		$16.4
Weighted Average Remaining Lease Term (Years):
Operating Leases - Vehicles and Equipment	4		3
Operating Leases - Land and Other	16		27
Weighted Average Discount Rate:
Operating Leases - Vehicles and Equipment	3.9	%	3.8	%
Operating Leases - Land and Other	3.9	%	4.5	%

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

Maturities of lease liabilities were as follows:

	December 31, 2022
Millions
2023	$3.4
2024	3.1
2025	2.9
2026	2.9
2027	3.8
Thereafter	1.2
Total Lease Payments Due	17.3
Less: Imputed Interest	4.8
Total Lease Obligations	12.5
Less: Current Lease Obligations	3.2
Total Long-term Lease Obligations	$9.3

Other Income (Expense) - Other [Table Text Block]

Other Income (Expense) - Other
Year Ended December 31	2022	2021	2020
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credit (a)	$9.8	$6.1	$8.6
Interest and Investment Earnings	—	2.3	1.6
AFUDC - Equity	2.7	2.6	1.9
Gain on Land Sales	—	0.1	0.4
PSA Liability (b)	10.2	—	—
Other	(0.3)	(2.4)	2.2
Total Other Income (Expense) - Other	$22.4	$8.7	$14.7

(a)These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)

(b)The gain on removal of the PSA liability for the Northern Wind project upon decommissioning of the legacy wind energy facility assets, which was more than offset by a reserve for an anticipated loss on the sale of the Northern Wind project, was recorded in Cost of Sales - Non-Utility on the Consolidated Statement of Income.

Schedule of Error Corrections and Prior Period Adjustments

A summary of the effect of the revision on the Consolidated Statements of Income and Consolidated Statement of Comprehensive Income for the year ended December 31, 2020 is as follows:

Revision Impacts for the Year Ended December 31, 2020	As Reported	Adjustment	As Revised
Millions Except Per Share Amounts
Impairment of Property, Plant and Equipment	—	$12.7	$12.7
Income Tax Benefit	$(39.5)	(3.9)	(43.4)
Net Income Attributable to ALLETE	$174.2	$(8.8)	$165.4
Comprehensive Income Attributable to ALLETE	$166.7	$(8.8)	$157.9
Diluted Earnings Per Share	$3.35	$(0.17)	$3.18

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

A summary of the effect of the revision on the Consolidated Balance Sheet as of December 31, 2021 is as follows:

Revision Impacts for the Year Ended December 31, 2021	As Reported	Adjustment	As Revised
Millions
Property, Plant and Equipment - Net	$5,100.2	$(12.7)	$5,087.5
Total Assets	$6,435.0	$(12.7)	$6,422.3
Deferred Income Taxes	$185.7	$(3.9)	$181.8
Total Liabilities	$3,488.7	$(3.9)	$3,484.8
Retained Earnings	$900.2	$(8.8)	$891.4
Total Equity	$2,946.3	$(8.8)	$2,937.5

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment and Estimated Useful Lives of Property, Plant and Equipment [Table Text Block]

Property, Plant and Equipment
As of December 31	2022	2021
Millions
Regulated Operations
Property, Plant and Equipment in Service	$5,198.6	$5,028.7
Construction Work in Progress	74.0	108.7
Accumulated Depreciation	(1,972.3)	(1,834.6)
Regulated Operations – Net	3,300.3	3,302.8
ALLETE Clean Energy
Property, Plant and Equipment in Service	1,619.4	1,704.2
Construction Work in Progress	51.1	79.9
Accumulated Depreciation	(176.8)	(149.0)
ALLETE Clean Energy – Net	1,493.7	1,635.1
Corporate and Other (a)
Property, Plant and Equipment in Service	295.2	267.1
Construction Work in Progress	50.9	19.8
Accumulated Depreciation	(136.1)	(137.3)
Corporate and Other – Net	210.0	149.6
Property, Plant and Equipment – Net	$5,004.0	$5,087.5

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

Estimated Useful Lives of Property, Plant and Equipment (Years)
Regulated Operations
Generation	1 to 50	ALLETE Clean Energy	5 to 35
Transmission	50 to 75	Corporate and Other	3 to 50
Distribution	18 to 70

Asset Retirement Obligations [Table Text Block]

Asset Retirement Obligations
Millions
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
Accretion	9.5
Liabilities Recognized	7.8
Liabilities Settled	(4.4)
Revisions in Estimated Cash Flows	3.0
Obligation as of December 31, 2022	$200.4

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Jointly-Owned Facilities and Assets (Tables)

12 Months Ended

Dec. 31, 2022

Jointly-Owned Facilities and Assets [Abstract]

Jointly-Owned Facilities and Assets [Table Text Block]

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, 2022
Boswell Unit 4	$712.0	$340.1	$3.3	80
Transmission Assets	101.0	21.1	—	9.3 - 14.7
Total	$813.0	$361.2	$3.3
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

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities (Table Text Block)

Regulatory Assets and Liabilities
As of December 31	2022	2021
Millions
Current Regulatory Assets (a)
Fuel Adjustment Clause (b)	$25.6	—
Total Current Regulatory Assets	$25.6	—
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (c)	$225.9	$226.4
Income Taxes (d)	97.6	104.7
Cost Recovery Riders (e)	41.2	63.2
Asset Retirement Obligations (f)	35.6	33.1
Manufactured Gas Plant (g)	15.1	17.0
Fuel Adjustment Clause (b)	14.5	56.4
PPACA Income Tax Deferral	4.1	4.3
Other	7.0	6.7
Total Non-Current Regulatory Assets	$441.0	$511.8
Current Regulatory Liabilities (h)
Provision for Interim Rate Refund	$18.4	—
Fuel Adjustment Clause (b)	—	$5.0
Transmission Formula Rates	4.9	3.1
Other	0.1	0.5
Total Current Regulatory Liabilities	$23.4	$8.6
Non-Current Regulatory Liabilities
Income Taxes (d)	$332.5	$353.4
Wholesale and Retail Contra AFUDC (j)	80.7	83.7
Plant Removal Obligations (k)	60.0	52.6
Defined Benefit Pension and Other Postretirement Benefit Plans (c)	17.6	28.1
North Dakota Investment Tax Credits (l)	16.9	12.2
Boswell Units 1 and 2 Net Plant and Equipment (i)	6.7	0.4
Non-Jurisdictional Land Sales (m)	7.5	—
Other	4.2	5.7
Total Non-Current Regulatory Liabilities	$526.1	$536.1

(a)Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.

(b)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.)

(c)Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, 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 12. Pension and Other Postretirement Benefit Plans.)

(d)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.

(e)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 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, 2022, will be recovered within the next two years.

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

(g)This 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.

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

(i)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.

(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.

(m)This regulatory liability represents the net proceeds from the sale of certain land by Minnesota Power that is expected to be refunded to ratepayers through a future rate case or through its renewable resources rider.

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Acquisitions (Tables)

Apr. 15, 2022

Business Combination and Asset Acquisition [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

Millions
Assets Acquired
Cash and Cash Equivalents	$3.9
Accounts Receivable	1.4
Inventory (a)	25.3
Other Current Assets	12.8
Property, Plant and Equipment - Net	16.4
Goodwill (b)	154.9
Other Non-Current Assets	2.1
Total Assets Acquired	$216.8
Liabilities Assumed
Current Liabilities	$23.6
Long-Term Debt Due Within One Year	28.3
Long-Term Debt	5.9
Other Non-Current Liabilities	0.2
Total Liabilities Assumed	$58.0
Net Identifiable Assets Acquired	$158.8

(a)Includes $11.6 million of purchase price accounting for certain projects under development at the time of acquisition.

(b)For tax purpose, the purchase price allocation resulted in $154.9 million of deductible goodwill.

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Equity Investments (Tables)

12 Months Ended

Dec. 31, 2022

ATC [Member]

Equity Investments [Line Items]

Equity Investments [Table Text Block]

ALLETE’s Investment in ATC
Year Ended December 31	2022	2021
Millions
Equity Investment Beginning Balance	$154.5	$149.0
Cash Investments	5.9	—
Equity in ATC Earnings	19.3	21.3
Distributed ATC Earnings	(15.5)	(17.2)
Amortization of the Remeasurement of Deferred Income Taxes	1.2	1.4
Equity Investment Ending Balance	$165.4	$154.5

ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2022	2021
Millions
Current Assets	$89.6	$89.8
Non-Current Assets	5,997.8	5,628.1
Total Assets	$6,087.4	$5,717.9
Current Liabilities	$511.9	$436.9
Long-Term Debt	2,613.0	2,513.0
Other Non-Current Liabilities	485.8	422.0
Members’ Equity	2,476.7	2,346.0
Total Liabilities and Members’ Equity	$6,087.4	$5,717.9

Income Statement Data
Year Ended December 31	2022	2021	2020
Millions
Revenue	$751.2	$754.8	$758.1
Operating Expense	381.5	376.2	372.4
Other Expense	122.9	113.9	110.9
Net Income	$246.8	$264.7	$274.8
ALLETE’s Equity in Net Income	$19.3	$21.3	$22.3

Nobles 2 [Member]

Equity Investments [Line Items]

Equity Investments [Table Text Block]

ALLETE’s Investment in Nobles 2
Millions
Equity Investment Balance as of December 31, 2021	$163.5
Equity in Nobles 2 Earnings (a)	(0.6)
Distributed Nobles 2 Earnings	(5.6)
Equity Investment Balance as of December 31, 2022	$157.3

(a)The Company also recorded net loss attributable to non-controlling interest of $10.6 million related to its investment in Nobles 2

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities	$7.7	—	—	$7.7
Available-for-sale – Corporate and Governmental Debt Securities (b)	—	$5.7	—	5.7
Cash Equivalents	4.2	—	—	4.2
Total Fair Value of Assets	$11.9	$5.7	—	$17.6
Liabilities:
Deferred Compensation (c)	—	$15.0	—	$15.0
Total Fair Value of Liabilities	—	$15.0	—	$15.0

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

(b)As of December 31, 2022, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $2.7 million, in three years to less than five years was $1.9 million and in five or more years was $0.4 million.

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

	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	—	$6.2	—	6.2
Cash Equivalents	2.5	—	—	2.5
Total Fair Value of Assets	$11.4	$6.2	—	$17.6
Liabilities: (b)
Deferred Compensation	—	$18.0	—	$18.0
Total Fair Value of Liabilities	—	$18.0	—	$18.0

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

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

Financial Instruments [Table Text Block]

Financial Instruments	Carrying Amount	Fair Value
Millions
Short-Term and Long-Term Debt (a)
December 31, 2022	$1,929.1	$1,782.7
December 31, 2021	$1,986.4	$2,192.6

(a) Excludes unamortized debt issuance costs.

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Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Long-term Debt [Table Text Block]

Long-Term Debt
As of December 31	2022	2021
Millions
First Mortgage Bonds
3.40% Series Due 2022	—	$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	100.0
4.54% Series Due 2032	75.0	—
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
Armenia Mountain Senior Secured Notes 3.26% Due 2024	19.3	29.1
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8	27.8
Revolving Credit Facility Variable Rate Due 2026	13.0	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 2022	—	110.0
Unsecured Term Loan Variable Rate Due 2023	170.0	—
Other Long-Term Debt, 2022 Weighted Average Rate 4.94% Due 2024 – 2051	82.0	57.5
Unamortized Debt Issuance Costs	(8.3)	(9.0)
Total Long-Term Debt	1,920.8	1,977.4
Less: Due Within One Year	272.6	214.2
Net Long-Term Debt	$1,648.2	$1,763.2

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Commitments, Guarantees and Contingencies (Tables)

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Annual Payments for Certain Long-Term Commitments [Table Text Block]

The following table details the estimated minimum payments for certain long-term commitments as of December 31, 2022:

	2023	2024	2025	2026	2027	Thereafter
Millions
Capital Purchase Obligations	$26.6	$10.6	$1.3	$2.7	—	$0.6
Easements (a)	$7.8	$7.9	$8.0	$8.1	$8.2	$206.9
PPAs (b)	$151.3	$145.8	$137.0	$136.9	$123.6	$1,010.3
Other Purchase Obligations (c)	$49.9	$10.2	$6.5	—	—	—

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

(b)Does not include 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.

Minnesota Power has also entered into the following long-term PPAs for the purchase of capacity and energy as of December 31, 2022:

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

(a)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.

(b)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, 2022:

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 32 percent in 2022 (28 percent in 2021 and in 2020). (See Square Butte PPA.)

(c)Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of 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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Common Stock and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Summary of Common Stock [Table Text Block]

Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2019	51,679	$1,436.7
Employee Stock Purchase Plan	13	0.7
Invest Direct	309	18.3
Share-Based Compensation	84	5.2
Balance as of December 31, 2020	52,085	1,460.9
Employee Stock Purchase Plan	17	0.8
Invest Direct	263	17.5
Share-Based Compensation	73	6.5
Equity Issuance Program	782	51.0
Balance as of December 31, 2021	53,220	1,536.7
Employee Stock Purchase Plan	11	0.9
Invest Direct	244	14.9
Share-Based Compensation	82	5.3
Equity Issuance	3,680	223.7
Balance as of December 31, 2022	57,237	$1,781.5

Reconciliation of Basic and Diluted Earnings Per Share [Table Text Block]

Reconciliation of Basic and Diluted
Earnings Per Share		Dilutive
Year Ended December 31	Basic	Securities	Diluted
Millions Except Per Share Amounts
2022
Net Income Attributable to ALLETE	$189.3		$189.3
Average Common Shares	55.9	0.1	56.0
Earnings Per Share	$3.38		$3.38
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	$165.4		$165.4
Average Common Shares	51.9	—	51.9
Earnings Per Share	$3.18		$3.18

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Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]

Income Tax Expense
Year Ended December 31	2022	2021	2020
Millions
Current Income Tax Expense (a)
Federal	$1.2	—	—
State	6.1	—	—
Total Current Income Tax Expense	$7.3	—	—
Deferred Income Tax Expense (Benefit)
Federal (b)	$(32.8)	$(37.2)	$(51.5)
State (c)	(5.2)	10.8	8.6
Investment Tax Credit Amortization	(0.5)	(0.5)	(0.5)
Total Deferred Income Tax Expense (Benefit)	$(38.5)	$(26.9)	$(43.4)
Total Income Tax Expense (Benefit)	$(31.2)	$(26.9)	$(43.4)

(a)For the years ended December 31, 2021 and 2020, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of certain tax legislation. Federal and state NOLs are being carried forward to offset current and future taxable income. For the year ended December 31, 2022, federal NOLs were fully utilized and production tax credits were used to partially offset federal taxable income.

(b)For the years ended December 31, 2022, 2021 and 2020, the federal tax benefit is primarily due to production tax credits.

(c)For the year ended December 31, 2022, the state impact includes the benefit of deferred repricing as a result of the New Energy acquisition.

Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Table Text Block]

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2022		2021		2020
Millions
Income Before Non-Controlling Interest and Income Taxes	$100.1		$110.9		$109.4
Statutory Federal Income Tax Rate	21	%	21	%	21	%
Income Taxes Computed at Statutory Federal Rate	$21.0		$23.3		$23.0
Increase (Decrease) in Tax Due to:
State Income Taxes	8.6		8.6		6.5
Deferred Income Tax Revaluation	(7.9)		—		—
Production Tax Credits	(50.7)		(53.5)		(62.7)
Investment Tax Credits	(4.1)		—		—
Regulatory Differences – Excess Deferred Tax Benefit (a)	(9.1)		(9.5)		(9.9)
Non-Controlling Interest	11.2		6.3		2.7
AFUDC - Equity	(1.1)		(1.0)		(0.8)
Other	0.9		(1.1)		(2.2)
Total Income Tax Benefit	$(31.2)		$(26.9)		$(43.4)

(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.)

Deferred Tax Assets and Liabilities [Table Text Block]

Deferred Income Tax Assets and Liabilities
As of December 31	2022	2021
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation	$46.4	$44.5
Property-Related	61.9	54.8
NOL Carryforwards	16.7	67.5
Capital Loss Carryforwards	13.1	—
Tax Credit Carryforwards	548.7	509.1
Power Sales Agreements	13.7	16.5
Regulatory Liabilities	95.5	101.5
Other	28.1	18.0
Gross Deferred Income Tax Assets	824.1	811.9
Deferred Income Tax Asset Valuation Allowance	(60.2)	(69.0)
Total Deferred Income Tax Assets	$763.9	$742.9
Deferred Income Tax Liabilities
Deferred Gain	$7.9	$7.9
Property-Related	661.7	680.8
Regulatory Asset for Benefit Obligations	57.7	54.9
Unamortized Investment Tax Credits	30.0	30.5
Partnership Basis Differences	126.0	106.3
Fuel Adjustment Clause	10.7	14.3
Regulatory Assets	28.0	30.0
Total Deferred Income Tax Liabilities	$922.0	$924.7
Net Deferred Income Taxes (a)	$158.1	$181.8

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

NOL and Tax Credit Carryforwards [Table Text Block]

NOL and Tax Credit Carryforwards
As of December 31	2022	2021
Millions
Federal NOL Carryforwards (a)	—	$177.3
Federal Tax Credit Carryforwards	$464.5	$416.4
Federal Capital Loss (a)	$35.1	—
State NOL Carryforwards (a)	$323.0	$506.9
State Tax Credit Carryforwards (b)	$24.5	$24.2
State Capital Loss (a)	$83.2	—

(a)Pre-tax amounts.

(b)Net of a $59.6 million valuation allowance as of December 31, 2022 ($68.6 million as of December 31, 2021).

Gross Unrecognized Income Tax Benefits [Table Text Block]

Gross Unrecognized Income Tax Benefits	2022	2021	2020
Millions
Balance at January 1	$1.3	$1.4	$1.4
Additions for Tax Positions Related to the Current Year	—	—	0.1
Reductions for Tax Positions Related to Prior Years	—	(0.1)	(0.1)
Balance as of December 31	$1.3	$1.3	$1.4

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Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2022

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]

Estimated Future Benefit Payments	Pension	Postretirement Health and Life
Millions
2023	$58.0	$7.2
2024	$58.4	$7.5
2025	$58.0	$7.5
2026	$57.3	$7.7
2027	$57.0	$8.0
Years 2028 – 2032	$274.9	$42.4

Weighted Average Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs [Table Text Block]

Weighted Average Assumptions Used to Determine Benefit Obligation
As of December 31	2022	2021
Discount Rate
Pension	5.70%	3.05%
Postretirement Health and Life	5.68%	3.09%
Rate of Compensation Increase	3.58%	3.58%
Health Care Trend Rates
Trend Rate	6.50%	5.66%
Ultimate Trend Rate	5.00%	4.50%
Year Ultimate Trend Rate Effective	2038	2038

Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2022	2021	2020
Discount Rate
Pension	3.28%	2.87%	3.52%
Postretirement Health and Life	3.09%	2.70%	3.45%
Expected Long-Term Return on Plan Assets
Pension	6.00%	6.50%	6.75%
Postretirement Health and Life	5.41%	5.85%	6.08%
Rate of Compensation Increase	3.58%	3.62%	4.06%

Plan Asset Actual and Target Allocations [Table Text Block]

Actual Plan Asset Allocations	Pension		Postretirement Health and Life (a)
	2022	2021	2022	2021
Equity Securities	46%	49%	66%	70%
Fixed Income Securities	50%	48%	34%	29%
Private Equity	—	—	—	1%
Real Estate	4%	3%	—	—
	100%	100%	100%	100%

(a)Includes VEBAs and irrevocable grantor trusts.

Following are the current targeted allocations as of December 31, 2022:

Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	49	%	65	%
Fixed Income Securities	50	%	35	%
Real Estate	1	%	—
	100	%	100	%

(a)Includes VEBAs and irrevocable grantor trusts.

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]

Pension Obligation and Funded Status
As of December 31	2022	2021
Millions
Accumulated Benefit Obligation	$724.5	$875.5
Change in Benefit Obligation
Obligation, Beginning of Year	$911.7	$965.7
Service Cost	9.3	11.0
Interest Cost	27.2	24.6
Plan Amendments	0.8	—
Plan Curtailments	—	(1.4)
Actuarial Gain (a)	(160.6)	(39.0)
Benefits Paid	(58.9)	(56.5)
Participant Contributions	10.2	7.3
Obligation, End of Year	$739.7	$911.7
Change in Plan Assets
Fair Value, Beginning of Year	$745.7	$759.4
Actual Return on Plan Assets	(130.5)	23.1
Employer Contribution (b)	12.3	19.7
Benefits Paid	(58.9)	(56.5)
Fair Value, End of Year	$568.6	$745.7
Funded Status, End of Year	$(171.1)	$(166.0)
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(2.1)	$(2.1)
Non-Current Liabilities (c)	$(169.0)	$(163.9)

(a)    Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

(b)    Includes Participant Contributions noted above, any contributions made by the Company to pension plan trusts and any direct benefit payments made under certain plans.

(c)    Presented here net of amounts related to prepaid pension for SWL&P that are reclassified to Regulatory Assets on the Consolidated Balance Sheet.

Amounts Recognized in Consolidated Balance Sheet [Table Text Block]

Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2022	2021
Millions
Net Loss	$(260.2)	$(260.2)
Prior Service Credit	0.1	1.0
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	89.0	93.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(171.1)	$(166.0)

Components of Net Periodic Cost [Table Text Block]

Components of Net Periodic Pension Cost
Year Ended December 31	2022	2021	2020
Millions
Service Cost	$9.3	$11.0	$10.7
Non-Service Cost Components (a)
Interest Cost	27.2	24.6	27.9
Expected Return on Plan Assets	(41.5)	(43.4)	(42.7)
Amortization of Loss	11.4	18.8	12.8
Amortization of Prior Service Credit	(0.1)	(0.2)	(0.2)
Net Pension Cost	$6.3	$10.8	$8.5

(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.

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets [Table Text Block]

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2022	2021
Millions
Projected Benefit Obligation	$739.7	$911.7
Accumulated Benefit Obligation	$724.5	$875.5
Fair Value of Plan Assets	$568.6	$745.7

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities [Table Text Block]

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2022	2021
Millions
Net (Gain) Loss	$11.4	$(20.1)
Amortization of Prior Service Credit	0.1	0.2
Prior Service Credit Arising During the Period	0.8	—
Amortization of Loss	(11.4)	(18.8)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$0.9	$(38.7)

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—	$61.2	—	$61.2
U.S. Mid-cap Growth (a)	—	40.0	—	40.0
U.S. Small-cap (a)	—	35.4	—	35.4
International	$127.0	—	—	127.0
Fixed Income Securities (a)	—	275.3	—	275.3
Cash and Cash Equivalents	7.3	—	—	7.3
Real Estate	—	—	$22.4	22.4
Total Fair Value of Assets	$134.3	$411.9	$22.4	$568.6

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

	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
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 [Table Text Block]

Recurring Fair Value Measures
Activity in Level 3	Real Estate
Millions
Balance as of December 31, 2021	$21.6
Actual Return on Plan Assets	1.0
Purchases, Sales, and Settlements – Net	(0.2)
Balance as of December 31, 2022	$22.4

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

Postretirement Health and Life [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]

Postretirement Health and Life Obligation and Funded Status
As of December 31	2022	2021
Millions
Change in Benefit Obligation
Obligation, Beginning of Year	$148.2	$167.6
Service Cost	3.0	3.6
Interest Cost	4.4	4.4
Actuarial Gain (a)	(38.7)	(19.7)
Benefits Paid	(9.2)	(10.6)
Participant Contributions	2.7	2.9
Obligation, End of Year	$110.4	$148.2
Change in Plan Assets
Fair Value, Beginning of Year	$201.8	$186.0
Actual Return on Plan Assets	(33.0)	22.8
Employer Contribution	0.3	0.7
Participant Contributions	2.7	2.9
Benefits Paid	(9.2)	(10.6)
Fair Value, End of Year	$162.6	$201.8
Funded Status, End of Year	$52.2	$53.6
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$58.8	$64.8
Current Liabilities	$(0.2)	$(1.4)
Non-Current Liabilities	$(6.4)	$(9.8)

(a)Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

Amounts Recognized in Consolidated Balance Sheet [Table Text Block]

Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2022	2021
Millions
Net Gain (a)	$9.2	$12.7
Prior Service Credit	13.2	20.7
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	29.8	20.2
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$52.2	$53.6

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

Components of Net Periodic Cost [Table Text Block]

Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2022	2021	2020
Millions
Service Cost	$3.0	$3.6	$3.3
Non-Service Cost Components (a)
Interest Cost	4.4	4.4	5.0
Expected Return on Plan Assets	(9.6)	(9.9)	(9.7)
Amortization of Loss	0.4	3.0	1.0
Amortization of Prior Service Credit	(7.5)	(7.6)	(8.0)
Effect of Plan Curtailment	—	—	(0.3)
Net Postretirement Health and Life Credit	$(9.3)	$(6.5)	$(8.7)

(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 Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities [Table Text Block]

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2022	2021
Millions
Net (Gain) Loss	$3.9	$(32.7)
Amortization of Prior Service Credit	7.5	7.6
Amortization of Loss	(0.4)	(3.0)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$11.0	$(28.1)

Unrecognized Postretirement Health and Life Costs [Table Text Block]

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	2022	2021
Millions
Net Gain	$(9.2)	$(12.7)
Prior Service Credit	(13.2)	(20.7)
Total Unrecognized Postretirement Health and Life Cost	$(22.4)	$(33.4)

Recurring Fair Value Measures [Table Text Block]

	Fair Value as of December 31, 2022
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap	$26.7	—	—	$26.7
U.S. Mid-cap Growth	25.5	—	—	25.5
U.S. Small-cap	12.7	—	—	12.7
International	41.5	—	—	41.5
Fixed Income Securities:
Mutual Funds	55.5	—	—	55.5
Cash and Cash Equivalents	0.7	—	—	0.7
Total Fair Value of Assets	$162.6	—	—	$162.6

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

	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 [Table Text Block]

Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2021	$2.0
Actual Return on Plan Assets	(1.5)
Purchases, Sales, and Settlements – Net	(0.5)
Balance as of December 31, 2022	—

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

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Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation Expense [Table Text Block]

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	2022	2021	2020
Millions
Performance Shares	$0.7	$2.0	$2.2
Restricted Stock Units	0.9	1.0	0.9
Total Share-Based Compensation Expense	$1.6	$3.0	$3.1
Income Tax Benefit	$0.5	$0.9	$0.9

Performance Shares [Table Text Block]

Performance Shares. The following table presents information regarding our non-vested performance shares.

	2022		2021		2020
	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	80,661	$75.80	85,284	$80.73	99,585	$72.78
Granted (a)	37,731	$67.22	33,304	$73.25	25,763	$83.17
Awarded	—	—	—	—	(25,304)	$62.03
Unearned Grant Award	(50,524)	$77.49	(33,375)	$86.09	(13,625)	$62.03
Forfeited	(7,379)	$71.00	(4,552)	$74.05	(1,135)	$79.81
Non-vested as of December 31	60,489	$69.62	80,661	$75.80	85,284	$80.73

(a)    Shares granted include accrued dividends.

Restricted Stock Units [Table Text Block]

Restricted Stock Units. The following table presents information regarding our available restricted stock units.

	2022		2021		2020
	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	28,141	$73.16	37,482	$77.64	39,943	$69.30
Granted (a)	15,477	$63.70	16,251	$64.97	15,169	$83.48
Awarded	(7,396)	$75.55	(23,631)	$74.53	(17,193)	$63.41
Forfeited	(2,658)	$66.44	(1,961)	$74.52	(437)	$77.52
Available as of December 31	33,564	$68.80	28,141	$73.16	37,482	$77.64

(a)    Shares granted include accrued dividends.

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Business Segment (Tables)

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Year Ended December 31	2022	2021	2020
Millions
Operating Revenue
Residential	$175.9	$160.8	$140.7
Commercial	187.2	168.6	139.5
Municipal	40.2	52.0	41.2
Industrial	589.0	565.5	432.8
Other Power Suppliers	165.8	168.7	138.8
Other	101.2	112.3	94.3
Total Regulated Operations	1,259.3	1,227.9	987.3
ALLETE Clean Energy
Long-term PSA	77.2	75.5	68.3
Sale of Wind Energy Facility	33.5	—	—
Other	7.6	11.4	11.3
Total ALLETE Clean Energy	118.3	86.9	79.6
Corporate and Other
Long-term Contract	89.2	84.4	86.0
Sale of Renewable Development Projects	73.9	—	—
Other	30.0	20.0	16.2
Total Corporate and Other	193.1	104.4	102.2
Total Operating Revenue	$1,570.7	$1,419.2	$1,169.1
Net Income Attributable to ALLETE (a)
Regulated Operations	$149.9	$129.1	$136.3
ALLETE Clean Energy	16.3	26.3	21.1
Corporate and Other (b)(c)	23.1	13.8	8.0
Total Net Income Attributable to ALLETE	$189.3	$169.2	$165.4

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. 

(b)    Net Income in 2022 includes a $8.3 million after-tax expense as a result of purchase price accounting related to projects under development at the time of acquisition and $2.7 million after-tax of transaction costs related to the acquisition of New Energy.

(c)    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.)

Year Ended December 31	2022	2021	2020
Millions
Depreciation and Amortization
Regulated Operations	$171.9	$170.7	$166.9
ALLETE Clean Energy	58.6	49.2	37.9
Corporate and Other	11.7	11.8	13.0
Total Depreciation and Amortization	$242.2	$231.7	$217.8
Impairment of Property, Plant and Equipment
ALLETE Clean Energy	—	—	$12.7
Interest Expense (a)
Regulated Operations	$58.1	$57.3	$58.5
ALLETE Clean Energy	2.3	1.5	2.2
Corporate and Other	19.6	13.2	13.2
Eliminations	(4.8)	(2.9)	(8.3)
Total Interest Expense	$75.2	$69.1	$65.6
Equity Earnings
Regulated Operations	$19.3	$21.3	$22.3
Corporate and Other	(0.6)	(1.3)	(0.2)
Total Equity Earnings	$18.7	$20.0	$22.1
Income Tax Expense (Benefit)
Regulated Operations	$(10.4)	$(16.6)	$(19.4)
ALLETE Clean Energy	(15.4)	(16.6)	(23.0)
Corporate and Other	(5.4)	6.3	(1.0)
Total Income Tax Benefit	$(31.2)	$(26.9)	$(43.4)

(a)    Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.    

As of December 31	2022	2021
Millions
Assets
Regulated Operations	$4,291.4	$4,289.4
ALLETE Clean Energy	1,873.3	1,706.7
Corporate and Other	680.9	426.2
Total Assets	$6,845.6	$6,422.3
Capital Expenditures
Regulated Operations	$158.3	$166.8
ALLETE Clean Energy	2.2	269.9
Corporate and Other	47.6	39.7
Total Capital Expenditures	$208.1	$476.4

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2022

Selected Quarterly Financial Information [Abstract]

Quarterly Financial Data (Unaudited) [Table Text Block]

Quarter Ended	Mar. 31	Jun. 30	Sept. 30	Dec. 31
Millions Except Earnings Per Share
2022
Operating Revenue	$383.5	$373.1	$388.3	$425.8
Operating Income	$53.4	$13.7	$33.4	$33.7
Net Income Attributable to ALLETE	$66.3	$37.6	$33.7	$51.7
Earnings Per Share of Common Stock
Basic	$1.24	$0.67	$0.59	$0.90
Diluted	$1.24	$0.67	$0.59	$0.90
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 (a)
Operating Revenue	$311.6	$243.2	$293.9	$320.4
Operating Income	$60.2	$12.7	$41.6	$23.7
Net Income Attributable to ALLETE	$66.3	$20.1	$40.7	$38.3
Earnings Per Share of Common Stock
Basic	$1.28	$0.39	$0.78	$0.74
Diluted	$1.28	$0.39	$0.78	$0.73

(a)    See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

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Operations and Significant Accounting Policies - Business Segments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Customers MW	Dec. 31, 2021
Business Segments [Line Items]
Number of Reportable Segments	2	3
Square Butte [Member] | Square Butte PPA [Member]
Business Segments [Line Items]
Minnesota Power Output Entitlement (MW) | MW	227.5
Nemadji Trail Energy Center [Member]
Business Segments [Line Items]
Estimated Capital Expenditures, Including Past Expenditures | $	$ 700
Square Butte [Member] | Square Butte [Member] | Square Butte PPA [Member]
Business Segments [Line Items]
Generating Capacity Counterparty Owned (MW) | MW	455
Minnesota Power [Member] | Square Butte [Member] | Square Butte [Member] | Square Butte PPA [Member]
Business Segments [Line Items]
Expected Output Entitlement (Percent)	50.00%
South Shore Energy | Nemadji Trail Energy Center [Member]
Business Segments [Line Items]
Capital Cost Spent to Date | $	$ 7
Estimated Capital Expenditures, ALLETE Portion | $	$ 150
New Energy
Business Segments [Line Items]
Discount Rate - Input for Goodwill Analysis	14.00%
Terminal Growth Rate - Input for Goodwill Analysis	3.50%
Regulated Operations [Member] | Minnesota Power [Member] | Retail Customers [Member] | Electric Rates [Member]
Business Segments [Line Items]
Number of Customers	150,000
Regulated Operations [Member] | Minnesota Power [Member] | Municipal Customers [Member] | Electric Rates [Member]
Business Segments [Line Items]
Number of Customers	14
Regulated Operations [Member] | SWL&P [Member] | Retail Customers [Member] | Electric Rates [Member]
Business Segments [Line Items]
Number of Customers	15,000
Regulated Operations [Member] | SWL&P [Member] | Retail Customers [Member] | Natural Gas [Member]
Business Segments [Line Items]
Number of Customers	13,000
Regulated Operations [Member] | SWL&P [Member] | Retail Customers [Member] | Water [Member]
Business Segments [Line Items]
Number of Customers	10,000
ALLETE Clean Energy [Member] | ALLETE Clean Energy [Member]
Business Segments [Line Items]
Energy Generation Owned (MW) | MW	1,200
Generating Capacity Under Construction (MW) | MW	100
Corporate and Other [Member] | BNI Energy [Member]
Business Segments [Line Items]
Number of Customers	2
Corporate and Other [Member] | BNI Energy [Member] | Square Butte [Member]
Business Segments [Line Items]
Number of Customers	1
Nobles 2 [Member]
Business Segments [Line Items]
Ownership Percentage	49.00%
Natural Gas-Fired [Member] | Nemadji Trail Energy Center [Member]
Business Segments [Line Items]
Generating Capacity Jointly Owned (MW) | MW	600
Natural Gas-Fired [Member] | South Shore Energy | Nemadji Trail Energy Center [Member]
Business Segments [Line Items]
Expected Output Entitlement (Percent)	20.00%
Wind Turbine Generators [Member] | Minnesota Power [Member] | Tenaska [Member] | Nobles 2 PPA [Member]
Business Segments [Line Items]
Generating Capacity Counterparty Owned (MW) | MW	250
Contract Term (Years)	20 years

XML

Operations and Significant Accounting Policies - Balance Sheet and Income Statement Disclosures (Details) - USD ($)		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and Cash Equivalents		$ 36,400,000	$ 45,100,000	$ 44,300,000
Restricted Cash included in Prepayments and Other		1,500,000	300,000	800,000
Restricted Cash included in Other Non-Current Assets		2,300,000	2,300,000	20,100,000
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		40,200,000	47,700,000	65,200,000	$ 92,500,000
Accounts Receivable [Abstract]
Billed		107,100,000	100,600,000
Unbilled		29,200,000	24,700,000
Less: Allowance for Doubtful Accounts		1,600,000	1,800,000
Total Accounts Receivable		134,700,000	123,500,000
Nontrade Receivables, Current		3,200,000	200,000
Accounts Receivable, Allowance		137,900,000	123,700,000
Inventories – Net [Abstract]
Fuel	[1]	33,400,000	18,700,000
Materials and Supplies		75,100,000	56,100,000
Construction of Wind Energy Facilities	[2]	347,400,000	22,900,000
Total Inventories – Net		455,900,000	97,700,000
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use		0	0
Other Non-Current Assets [Abstract]
Contract Asset - Noncurrent	[3]	21,000,000	23,300,000
Operating Lease, Right-of-Use Asset		12,700,000	16,400,000
ALLETE Properties		19,100,000	19,400,000
Restricted Cash, Noncurrent		2,300,000	2,300,000	$ 20,100,000
Other Postretirement Benefit Plans		58,800,000	64,800,000
Other		90,400,000	86,700,000
Total Other Non-Current Assets		204,300,000	212,900,000
Other Liabilities [Abstract]
Customer Deposits	[4]	150,700,000	27,200,000
PSAs		6,100,000	12,600,000
Manufactured Gas Plant - Current	[5]	14,700,000	12,800,000
Fuel Adjustment Clause		0	5,000,000.0
Operating Lease Liabilities, Current		3,200,000	4,800,000
Public Utilities - Reserve for Interim Rate Refund		18,400,000	0
Redeemable Non-Controlling Interest	[6]	0	30,600,000
Other		57,900,000	40,000,000.0
Total Other Current Liabilities		251,000,000.0	133,000,000.0
Asset Retirement Obligation	[7]	200,400,000	184,500,000
PSAs		26,900,000	39,500,000
Operating Lease Liabilities, Non-Current		9,300,000	11,600,000
Other		32,400,000	45,200,000
Total Other Non-Current Liabilities		$ 269,000,000.0	$ 280,800,000
Income Taxes [Abstract]
More-Likely-Than-Not Percentage		50.00%	50.00%
BNI Energy [Member]
Business Segments [Line Items]
Other Receivables		$ 32,400,000	$ 28,500,000
Taconite Harbor [Member] | Resource Package [Member] | MPUC [Member]
Property, Plant and Equipment [Line Items]
Net Book Value		25,000,000
Boswell Unit 3 [Member] | 2021 Integrated Resource Plan [Member] | MPUC [Member]
Property, Plant and Equipment [Line Items]
Net Book Value		235,000,000
Boswell Unit 4 [Member] | 2021 Integrated Resource Plan [Member] | MPUC [Member]
Property, Plant and Equipment [Line Items]
Net Book Value		$ 435,000,000

[1] Fuel consists primarily of coal inventory at Minnesota Power.

[2] Project costs related to ALLETE Clean Energy’s Northern Wind project sold in January 2023 and Red Barn wind project which is expected to be sold in the first half 2023. (See Other Current Liabilities.)

[3] 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.

[4] Primarily related to deposits received by ALLETE Clean Energy for the Northern Wind project sold in January 2023 and the Red Barn wind project which is expected to be sold in the first half of 2023. (See Inventories – Net.)

[5] 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 9. Commitments, Guarantees and Contingencies.)

[6] 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.

[7] The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $32.4 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2022 ($28.5 million as of December 31, 2021).

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Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Details)	12 Months Ended
	Dec. 31, 2022 Customers MW	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	4 years
Revenue, Performance Obligation, Description of 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.
Regulated Operations [Member] | Alternative Programs [Member]
Disaggregation of Revenue [Line Items]
Revenue Collection Period Following the Annual Period it is Recognized	24 months
Regulated Operations [Member] | Retail Electric Service [Member] | Industrial [Member] | Industrial Customers [Member]
Disaggregation of Revenue [Line Items]
Percentage of Total Regulated Utility kWh Sales	52.00%
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Wholesale Electric Service [Member] | Municipal [Member] | Municipal Customers [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	14
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Retail Electric Service [Member] | Industrial [Member] | Industrial Customers [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	4 years
Large Power Customer Contracts	7
Contract Serving Requirement | MW	10
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Retail Electric Service [Member] | Municipal Customers [Member] | Municipal [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	3 years
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Sale of Energy under PSA [Member] | Other Power Suppliers [Member] | Other Power Supplier Customers [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	1
Customer Concentration Risk [Member] | Large Power Customers [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	7
Customer Concentration Risk [Member] | Consolidated Operating Revenue [Member] | Large Power Customers [Member] | Largest Customer [Member]
Disaggregation of Revenue [Line Items]
Concentration Risk, Percentage	26.00%	28.00%	25.00%
Customer Concentration Risk [Member] | Consolidated Operating Revenue [Member] | Large Power Customers [Member] | Regulated Operations [Member] | Largest Customer [Member]
Disaggregation of Revenue [Line Items]
Concentration Risk, Percentage	32.00%	32.00%	29.00%

XML

Operations and Significant Accounting Policies - Non-Controlling Interest (Details)	12 Months Ended
	Dec. 31, 2022 MW
Glen Ullin Energy Center [Member]
Non-Controlling Interest Details [Line Items]
Generating Capacity Subject to Tax Equity Financing	106
South Peak [Member]
Non-Controlling Interest Details [Line Items]
Generating Capacity Subject to Tax Equity Financing	80
Diamond Spring [Member]
Non-Controlling Interest Details [Line Items]
Generating Capacity Subject to Tax Equity Financing	303
Caddo [Member]
Non-Controlling Interest Details [Line Items]
Generating Capacity Subject to Tax Equity Financing	303
Nobles 2 [Member]
Non-Controlling Interest Details [Line Items]
Generating Capacity Subject to Tax Equity Financing	250

XML

Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Continued) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Capitalized Contract Cost, Amortization	$ 2.4	$ 2.7
Length of Notice Required to Terminate Contract	4 years
Revenue, Performance Obligation, Description of 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.
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Industrial Customers [Member] | Industrial [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55.0
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Industrial Customers [Member] | Industrial [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55.0
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Industrial Customers [Member] | Industrial [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55.0
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Industrial Customers [Member] | Industrial [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55.0
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Industrial Customers [Member] | Industrial [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 15.0
Long-term Contract with Customer [Member] | Regulated Operations [Member] | Industrial Customers [Member] | Industrial [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	2 years
Revenue, Remaining Performance Obligation, Amount	$ 25.0

XML

Operations and Significant Accounting Policies - Concentration of Credit Risk (Details) - Customer Concentration Risk [Member] - Large Power Customers [Member] $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Customers	Dec. 31, 2021 USD ($)	Dec. 31, 2020
Concentration Risk [Line Items]
Number of Large Power Customers	7
Receivables from Large Power Customers | $	$ 11.3	$ 7.8
Number of entities	2
Largest Customer [Member] | Consolidated Operating Revenue [Member]
Concentration Risk [Line Items]
Percent of Operating Revenue	26.00%	28.00%	25.00%
Largest Customer [Member] | Consolidated Operating Revenue [Member] | Regulated Operations [Member]
Concentration Risk [Line Items]
Percent of Operating Revenue	32.00%	32.00%	29.00%

XML

Operations and Significant Accounting Policies - Revenue - Assets Recognized From the Costs to Obtain a Contract with a Customer (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Capitalized Contract Cost [Line Items]
Contract Asset - Noncurrent	[1]	$ 21.0	$ 23.3
Capitalized Contract Cost, Amortization		$ 2.4	$ 2.7

[1] 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.

XML

Operations and Significant Accounting Policies - Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Residual Value Guarantee, Description	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.
Operating Lease, Right-of-Use Asset	$ 12.7	$ 16.4
Operating Lease, Cost	6.3	6.7
Operating Lease, Payments	6.3	6.7
Operating Lease Liabilities, Current	3.2	4.8
Operating Lease Liabilities, Non-Current	9.3	11.6
Operating Lease, Liability	12.5	$ 16.4
Residual Value of Leased Asset	$ 3.0
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other	Other
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Non-Current Liabilities	Other Non-Current Liabilities
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Non-Current Assets	Other Non-Current Assets
Vehicles and Equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	4 years	3 years
Operating Lease, Weighted Average Discount Rate, Percent	3.90%	3.80%
Land and Other [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	16 years	27 years
Operating Lease, Weighted Average Discount Rate, Percent	3.90%	4.50%

XML

Operations and Significant Accounting Policies - Lease Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
2023	$ 3.4
2024	3.1
2025	2.9
2026	2.9
2027	3.8
Thereafter	1.2
Total Lease Payments Due	17.3
Less: Imputed Interest	4.8
Total Lease Obligations	12.5	$ 16.4
Less: Current Lease Obligations	3.2	4.8
Long-term Lease Obligations	$ 9.3	$ 11.6

XML

Operations and Significant Accounting Policies - Other Income (Expense) - Other (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other		$ 22.4	$ 8.7	$ 14.7
Pension and Other Postretirement Benefit Plans Non-Service Credit [Member]
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other	[1]	9.8	6.1	8.6
Interest and Investment Earnings [Member]
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other		0.0	2.3	1.6
AFUDC - Equity [Member]
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other		2.7	2.6	1.9
Gain on Land Sales [Member]
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other		0.0	0.1	0.4
PSA Liability
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other	[2]	10.2	0.0	0.0
Other Income (Expense) - Other [Member]
Other Income (Expense) - Other [Line Items]
Total Other Income (Expense) - Other		$ (0.3)	$ (2.4)	$ 2.2

[1] These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)

[2] The gain on removal of the PSA liability for the Northern Wind project upon decommissioning of the legacy wind energy facility assets, which was more than offset by a reserve for an anticipated loss on the sale of the Northern Wind project, was recorded in Cost of Sales - Non-Utility on the Consolidated Statement of Income.

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Operations and Significant Accounting Policies - Immaterial Revision of Prior Periods (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020		Sep. 30, 2020	[1]	Jun. 30, 2020	[1]	Mar. 31, 2020	[1]	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Impairment Charge - After Tax																			$ 8.8
Error Corrections and Prior Period Adjustments, Description																	We have identified an immaterial prior period error with respect to the recognition of a non-cash impairment expense for our Northern Wind operating assets in the fourth quarter of 2020 prior to the execution of the purchase and sales agreement for a repower and sale of the wind energy facility. Specifically, the remaining net book value of the property, plant and equipment used in the recoverability test was calculated incorrectly.
Loss on Impairment of Assets																	$ 0.0	$ 0.0	12.7
Income Tax Benefit																	(31.2)	(26.9)	(43.4)
Net Income Attributable to ALLETE	$ 51.7	$ 33.7	$ 37.6	$ 66.3	$ 61.9	$ 27.6	$ 27.9	$ 51.8	$ 38.3	[1]	$ 40.7		$ 20.1		$ 66.3		189.3	169.2	165.4
Comprehensive Income Attributable to ALLETE																	$ 188.7	$ 176.5	$ 157.9
Earnings Per Share	$ 0.90	$ 0.59	$ 0.67	$ 1.24	$ 1.18	$ 0.53	$ 0.53	$ 0.99	$ 0.73	[1]	$ 0.78		$ 0.39		$ 1.28		$ 3.38	$ 3.23	$ 3.18
Property, Plant and Equipment – Net	$ 5,004.0				$ 5,087.5												$ 5,004.0	$ 5,087.5
Assets	6,845.6				6,422.3												6,845.6	6,422.3
Deferred Income Taxes	158.1				181.8												158.1	181.8
Liabilities	3,497.3				3,484.8												3,497.3	3,484.8
Retained Earnings	934.8				891.4												934.8	891.4
Members' Equity	$ 3,348.3				2,937.5				$ 2,791.4								$ 3,348.3	2,937.5	$ 2,791.4
Previously Reported
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Loss on Impairment of Assets																			0.0
Income Tax Benefit																			(39.5)
Net Income Attributable to ALLETE																			174.2
Comprehensive Income Attributable to ALLETE																			$ 166.7
Earnings Per Share																			$ 3.35
Property, Plant and Equipment – Net					5,100.2													5,100.2
Assets					6,435.0													6,435.0
Deferred Income Taxes					185.7													185.7
Liabilities					3,488.7													3,488.7
Retained Earnings					900.2													900.2
Members' Equity					2,946.3													2,946.3
Revision of Prior Period - Adjusted Balance
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Loss on Impairment of Assets																			$ 12.7
Income Tax Benefit																			(43.4)
Net Income Attributable to ALLETE																			165.4
Comprehensive Income Attributable to ALLETE																			$ 157.9
Earnings Per Share																			$ 3.18
Property, Plant and Equipment – Net					5,087.5													5,087.5
Assets					6,422.3													6,422.3
Deferred Income Taxes					181.8													181.8
Liabilities					3,484.8													3,484.8
Retained Earnings					891.4													891.4
Members' Equity					2,937.5													2,937.5
Revision of Prior Period, Error Correction, Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Loss on Impairment of Assets																			$ 12.7
Income Tax Benefit																			(3.9)
Net Income Attributable to ALLETE																			(8.8)
Comprehensive Income Attributable to ALLETE																			$ (8.8)
Earnings Per Share																			$ (0.17)
Property, Plant and Equipment – Net					(12.7)													(12.7)
Assets					(12.7)													(12.7)
Deferred Income Taxes					(3.9)													(3.9)
Liabilities					(3.9)													(3.9)
Retained Earnings					(8.8)													(8.8)
Members' Equity					$ (8.8)													$ (8.8)

[1] See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

XML

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment – Net		$ 5,004.0	$ 5,087.5
Asset Retirement Obligation [Roll Forward]
Beginning Obligation		184.5	166.6
Accretion		9.5	8.8
Liabilities Recognized		7.8	4.5
Liabilities Settled		(4.4)	(5.2)
Revisions in Estimated Cash Flows		3.0	9.8
Ending Obligation		200.4	184.5
Regulated Operations [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment in Service		5,198.6	5,028.7
Construction Work in Progress		74.0	108.7
Accumulated Depreciation		(1,972.3)	(1,834.6)
Property, Plant and Equipment – Net		$ 3,300.3	3,302.8
Regulated Operations [Member] | Generation [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		1 year
Regulated Operations [Member] | Generation [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		50 years
Regulated Operations [Member] | Transmission [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		50 years
Regulated Operations [Member] | Transmission [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		75 years
Regulated Operations [Member] | Distribution [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		18 years
Regulated Operations [Member] | Distribution [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		70 years
ALLETE Clean Energy [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment in Service		$ 1,619.4	1,704.2
Construction Work in Progress		51.1	79.9
Accumulated Depreciation		(176.8)	(149.0)
Property, Plant and Equipment – Net		$ 1,493.7	1,635.1
ALLETE Clean Energy [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		5 years
ALLETE Clean Energy [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		35 years
Corporate and Other [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment in Service	[1]	$ 295.2	267.1
Construction Work in Progress	[1]	50.9	19.8
Accumulated Depreciation	[1]	(136.1)	(137.3)
Property, Plant and Equipment – Net	[1]	$ 210.0	$ 149.6
Corporate and Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		3 years
Corporate and Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives		50 years

[1] Primarily includes BNI Energy and a small amount of non-rate base generation.

XML

Jointly-Owned Facilities and Assets (Details) $ in Millions	Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)
Jointly-Owned Facilities and Assets [Line Items]
Plant in Service	$ 813.0	$ 783.7
Accumulated Depreciation	361.2	329.6
Construction Work in Progress	3.3	30.1
Transmission [Member] | Transmission Assets [Member]
Jointly-Owned Facilities and Assets [Line Items]
Plant in Service	101.0	101.0
Accumulated Depreciation	21.1	18.5
Construction Work in Progress	$ 0.0	$ 0.0
Transmission [Member] | Transmission Assets [Member] | Minimum [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	9.30%	9.30%
Transmission [Member] | Transmission Assets [Member] | Maximum [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	14.70%	14.70%
Boswell Unit 4 [Member] | Jointly-Owned Electricity Generation Plant [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	80.00%	80.00%
Generating Capacity Jointly Owned (MW) | MW	585
Plant in Service	$ 712.0	$ 682.7
Accumulated Depreciation	340.1	311.1
Construction Work in Progress	$ 3.3	$ 30.1
Boswell Unit 4 [Member] | Jointly-Owned Electricity Generation Plant [Member] | Minnesota Power [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	80.00%
Boswell Unit 4 [Member] | Jointly-Owned Electricity Generation Plant [Member] | WPPI Energy [Member]
Jointly-Owned Facilities and Assets [Line Items]
WPPI Energy Ownership %	20.00%

XML

Regulatory Matters - Electric Rates (Details) $ in Millions								3 Months Ended	4 Months Ended	8 Months Ended	12 Months Ended			18 Months Ended	24 Months Ended	36 Months Ended
		Jan. 23, 2023 USD ($)	Dec. 20, 2022 USD ($)	Jun. 01, 2022 USD ($)	Jan. 13, 2022 USD ($)	Nov. 01, 2021 USD ($)	Nov. 01, 2019	Jun. 30, 2021 USD ($)	Apr. 30, 2020 USD ($)	Dec. 31, 2020	Dec. 31, 2022 USD ($) Years Customers	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) Years Customers	Aug. 11, 2021 USD ($)
Regulatory Matters [Line Items]
Public Utilities - Reserve for Interim Rate Refund											$ 18.4	$ 0.0			$ 0.0	$ 18.4
Regulatory Assets											441.0	511.8			511.8	441.0
Regulatory Assets											$ 441.0	511.8			511.8	441.0
Cost Recovery Riders [Member]
Regulatory Matters [Line Items]
Alternative Revenue Program, Required Collection Period											2 years
Regulatory Assets	[1]										$ 41.2	63.2			63.2	41.2
Regulatory Assets	[1]										41.2	63.2			63.2	$ 41.2
MPUC [Member] | Fuel Adjustment Clause Filing [Member] | Minnesota Power [Member]
Regulatory Matters [Line Items]
Forced Outage Costs														$ 8.0
Administrative Law Judge Recommended Refund																	$ 5.0
Commission Approved Refund					$ 5.0
PSCW [Member] | 2018 Wisconsin General Rate Case [Member] | SWL&P [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity																10.40%
Approved Equity Ratio																55.00%
PSCW [Member] | 2022 Wisconsin General Rate Review | SWL&P [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase				3.60%
Requested Return on Equity				10.40%
Requested Equity Ratio				55.00%
Annual Additional Revenue Generated from Requested Final Rate Increase				$ 4.3
Approved Rate Increase - Amount			$ 3.3
PSCW [Member] | 2022 Wisconsin General Rate Case | SWL&P [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity			10.00%
Approved Equity Ratio			55.00%
Electric Rates [Member] | MPUC [Member] | Minnesota Cost Recovery Riders [Member] | Minnesota Power [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Revenue from Cost Recovery Riders											38.8	38.9	$ 29.9
Electric Rates [Member] | MPUC [Member] | 2020 Minnesota General Rate Review [Member] | Minnesota Power [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase							10.60%
Public Utilities, Interim Rate Increase (Decrease), Amount									$ 36.1
Proposed Ongoing Customer Rate Increase										4.10%
Public Utilities, Interim Rate Increase (Decrease), Percentage									5.80%
Public Utilities Reserve for Interim Rates (Recorded During Period)								$ 11.7
Electric Rates [Member] | MPUC [Member] | 2022 Minnesota General Rate Review | Minnesota Power [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase						18.00%
Requested Return on Equity						10.25%
Requested Equity Ratio						53.81%
Annual Additional Revenue Generated from Requested Final Rate Increase						$ 108.0
Public Utilities, Interim Rate Increase (Decrease), Amount						80.0
Public Utility - Additional Rider Revenue											9.0
Approximate Pre-Tax Reserve for Deferred Residential Customer Interim Rates											8.0
Customer Refund Liability, Current											18.0					$ 18.0
Electric Rates [Member] | MPUC [Member] | 2022 Minnesota General Rate Review | Minnesota Power [Member] | Retail Customers [Member] | Subsequent Event [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity		9.65%
Approved Equity Ratio		52.50%
Approved Rate Increase - Amount		$ 60.0
Public Utility - Additional Rider Revenue		$ 10.0
Electric Rates [Member] | MPUC [Member] | 2022 Minnesota General Rate Review | Minnesota Power [Member] | Residential [Member]
Regulatory Matters [Line Items]
Deferred Interim Rates						$ 8.0
Electric Rates [Member] | MPUC [Member] | Cost Recovery Riders [Member] | Minnesota Power [Member]
Regulatory Matters [Line Items]
Regulatory Assets											3.8					3.8
Regulatory Assets											3.8					3.8
Electric Rates [Member] | MPUC [Member] | Fuel Adjustment Clause | Minnesota Power [Member]
Regulatory Matters [Line Items]
Regulatory Assets												56.0			56.0
Regulatory Assets												$ 56.0			$ 56.0
Electric Rates [Member] | MPUC [Member] | 2016 Minnesota General Rate Review | Minnesota Power [Member] | Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity															9.25%
Approved Equity Ratio															53.81%
Electric Rates [Member] | MPUC [Member] | Fuel Adjustment Clause 2022 | Minnesota Power [Member]
Regulatory Matters [Line Items]
Regulatory Assets											13.0					13.0
Regulatory Assets											$ 13.0					$ 13.0
Electric Rates [Member] | FERC [Member] | FERC-Approved Wholesale Rates [Member] | Minnesota Power [Member] | Municipal Customers [Member]
Regulatory Matters [Line Items]
Number of Customers | Customers											14					14
Notice Required to Terminate (Years) | Years											3					3
Electric Rates [Member] | FERC [Member] | FERC-Approved Wholesale Rates [Member] | Minnesota Power [Member] | Municipal Customers [Member] | Wholesale Electric Contracts (Through 2029)
Regulatory Matters [Line Items]
Number of Customers | Customers											13					13
Electric Rates [Member] | FERC [Member] | FERC-Approved Wholesale Rates [Member] | Minnesota Power [Member] | Municipal Customers [Member] | Wholesale Electric Contract (Cost-Based Formula Methodology for Entire Term) [Member]
Regulatory Matters [Line Items]
Number of Customers | Customers											2					2

[1] 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 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, 2022, will be recovered within the next two years.

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Regulatory Matters - Integrated Resource Plan (Details) - MW	12 Months Ended
	Dec. 31, 2022	Feb. 01, 2021
Natural Gas-Fired [Member] | Nemadji Trail Energy Center [Member]
Regulatory Matters [Line Items]
Generating Capacity Jointly Owned (MW)	600
Natural Gas-Fired [Member] | South Shore Energy | Nemadji Trail Energy Center [Member]
Regulatory Matters [Line Items]
Expected Output Entitlement (Percent)	20.00%
MPUC [Member] | Renewable Generation [Member] | Maximum [Member] | 2021 Integrated Resource Plan [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)		700

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Regulatory Matters - Conservation Improvement Program (CIP) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Regulatory Matters [Line Items]
Conservation Improvement Program Goal, In 2 Years	$ 10.9
MPUC [Member] | CIP Consolidated Filing [Member] | Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Financial Incentive		$ 2.4	$ 2.4
MPUC [Member] | CIP Consolidated Filing Member | Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Financial Incentive	$ 1.9
MPUC [Member] | Minimum [Member]
Regulatory Matters [Line Items]
CIP Spending Minimum - Percentage	1.50%

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Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Dec. 31, 2022
Loss Contingencies [Line Items]
FERC Authorized Return on Common Equity	10.02%
FERC Authorized Return on Equity Including Incentive Adder	10.52%

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Regulatory Matters - Minnesota Solar Energy Standard (Details) $ in Millions	Dec. 31, 2022 USD ($) MW
Minnesota Power [Member] | Solar Generation
Regulatory Matters [Line Items]
Anticipated Generating Capacity to be Purchased (MW)	20
Corporate & Other - Other [Member] | Solar Generation
Regulatory Matters [Line Items]
Estimated Investment Amount | $	$ 40
MPUC [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
MPUC [Member] | Minimum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
Minnesota Solar Energy Standard - Small Scale Solar Mandate Percentage	10.00%
MPUC [Member] | Maximum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.04

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Regulatory Matters - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets and Liabilities Currently Earning a Return		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.
Non-Current Regulatory Assets		$ 441.0	$ 511.8
Regulated Utility - Interim Rate Refund	[1]	18.4	0.0
Current Regulatory Liability	[1]	23.4	8.6
Non-Current Regulatory Liabilities		526.1	536.1
Regulatory Asset	[2]	25.6	0.0
Transmission Formula Rates [Member]
Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liability	[1],[3]	4.9	3.1
Income Taxes [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities	[4]	332.5	353.4
Wholesale and Retail Contra AFUDC [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities	[5]	80.7	83.7
Plant Removal Obligations [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities	[6]	60.0	52.6
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities	[7]	17.6	28.1
North Dakota Investment Tax Credits [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities	[8]	16.9	12.2
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liability	[1]	0.1	0.5
Non-Current Regulatory Liabilities		4.2	5.7
Boswell 1 & 2 [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities	[9]	6.7	0.4
Fuel Adjustment Clause
Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liability	[1]	0.0	5.0
Non-Jurisdictional Land Sales
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		7.5	0.0
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets	[7]	225.9	226.4
Income Taxes [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets	[4]	97.6	104.7
Asset Retirement Obligation [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets	[10]	35.6	33.1
Manufactured Gas Plant [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets	[11]	15.1	17.0
PPACA Income Tax Deferral [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		4.1	4.3
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		7.0	6.7
Cost Recovery Riders [Member]
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets	[12]	41.2	63.2
Fuel Adjustment Clause
Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		14.5	56.4
Regulatory Asset, Current	[2]	$ 25.6	$ 0.0

[1] Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.

[2] Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.(b)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.)

[3] 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.)

[4] 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.

[5] 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.

[6] Non-legal plant removal obligations included in retail customer rates that have not yet been incurred.

[7] Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, 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 12. Pension and Other Postretirement Benefit Plans.)

[8] 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.

[9] 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.

[10] Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.

[11] This 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.

[12] 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 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, 2022, will be recovered within the next two years.

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Acquisitions (Details) - USD ($) $ in Millions			12 Months Ended
		Apr. 15, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows			$ 40.2	$ 47.7	$ 65.2	$ 92.5
Goodwill			154.9
New Energy
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		100.00%
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		$ 3.9
Accounts Receivable		1.4
Inventory	[1]	25.3
Other Current Assets		12.8
Property, Plant, and Equipment		16.4
Goodwill	[2]	154.9
Other Noncurrent Assets		2.1
Total Assets Acquired		216.8
Total Liabilities Assumed		58.0
Net Identifiable Assets Acquired		158.8
Current Liabilities		23.6
Long-Term Debt due Within One Year		28.3
Long-Term Debt		5.9
Other No-Current Liabilities		0.2
Business Combinations, Fair Value Adjustments		11.6
Business Acquisition, Goodwill, Expected Tax Deductible Amount		154.9
Business Combination, Acquisition Related Costs			$ 2.7
Transaction Purchase Price		165.5
Business Combination, Consideration Transferred		$ 158.8
Business Combination, Reason for Business Combination			The acquisition of New Energy is consistent with ALLETE’s stated strategy of additional investment in renewable energy and related infrastructure across North America to support the Company’s sustainability-in-action strategy while providing potential long-term earnings growth.
Business Combination, Goodwill Recognized, Description			The goodwill recorded is primarily attributable to the highly skilled workforce of New Energy and synergies expected to arise as a result of the acquisition.
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual			$ 80.2
Business Acquisition, Pro Forma Information, Description			The Company has not presented separate results of operations since closing or combined pro forma financial information of the Company and New Energy since the beginning of 2021, as the results of operations for New Energy are not material to the Company's consolidated financials.

[1] Includes $11.6 million of purchase price accounting for certain projects under development at the time of acquisition.

[2] For tax purpose, the purchase price allocation resulted in $154.9 million of deductible goodwill.

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Equity Investments (Details) $ in Millions			3 Months Ended																12 Months Ended
		Jan. 31, 2023 USD ($)	Dec. 31, 2022 USD ($) MW	Sep. 30, 2022 USD ($)	Jun. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)		Sep. 30, 2020 USD ($)	[1]	Jun. 30, 2020 USD ($)	[1]	Mar. 31, 2020 USD ($)	[1]	Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance						$ 318.0													$ 318.0
Cash Investments																			5.9	$ 17.6	$ 99.1
Equity Earnings																			18.7	20.0	22.1
Equity Investment Ending Balance			$ 322.7				$ 318.0												322.7	318.0
Assets [Abstract]
Total Current Assets			718.0				291.3												718.0	291.3
Total Assets			6,845.6				6,422.3												6,845.6	6,422.3
Liabilities and Equity [Abstract]
Liabilities, Current			716.2				543.4												716.2	543.4
Members' Equity			3,348.3				2,937.5				$ 2,791.4								3,348.3	2,937.5	2,791.4
Total Liabilities and Equity			6,845.6				6,422.3												6,845.6	6,422.3
Income Statement Data [Abstract]
Revenue			425.8	$ 388.3	$ 373.1	383.5	399.0	$ 345.4	$ 335.6	$ 339.2	320.4	[1]	$ 293.9		$ 243.2		$ 311.6		1,570.7	1,419.2	1,169.1
Net Income																			131.3	137.8	152.8
ALLETE's Equity in Net Income																			18.7	20.0	22.1
ATC [Member]
Assets [Abstract]
Total Current Assets			89.6				89.8												89.6	89.8
Assets, Noncurrent			5,997.8				5,628.1												5,997.8	5,628.1
Total Assets			6,087.4				5,717.9												6,087.4	5,717.9
Liabilities and Equity [Abstract]
Liabilities, Current			511.9				436.9												511.9	436.9
Long-Term Debt			2,613.0				2,513.0												2,613.0	2,513.0
Other Non-Current Liabilities			485.8				422.0												485.8	422.0
Members' Equity			2,476.7				2,346.0												2,476.7	2,346.0
Total Liabilities and Equity			6,087.4				5,717.9												6,087.4	5,717.9
Income Statement Data [Abstract]
Revenue																			751.2	754.8	758.1
Operating Expense																			381.5	376.2	372.4
Other Expense																			122.9	113.9	110.9
Net Income																			246.8	264.7	274.8
Approximate Refund for Reversal of FERC ROE Order			31.0																31.0
Approximate Refund for Reversale of FERC ROE Order, ALLETE's Proportionate Share																			2.4
Approximate Reduction in Pretax Income for FERC Proposal to Limit Incentive adder, ALLETE's Proportionate Share			$ 1.0																$ 1.0
FERC Proposed Reduction to Incentive Adder			0.50%																0.50%
Basis Point Incentive adder			50.00%																50.00%
ATC [Member]
Equity Investments [Line Items]
Ownership Percentage			8.00%																8.00%
Expected Additional Investment in 2022			$ 8.2																$ 8.2
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance						154.5				$ 149.0									154.5	149.0
Cash Investments																			5.9	0.0
Equity Earnings																			19.3	21.3	22.3
Distributed Earnings																			(15.5)	(17.2)
Amortization from the Remeasurement of Deferred Income Taxes for Equity Method Investments																			1.2	1.4
Equity Investment Ending Balance			$ 165.4				154.5				$ 149.0								165.4	154.5	149.0
Income Statement Data [Abstract]
ALLETE's Equity in Net Income																			$ 19.3	21.3	$ 22.3
Authorized Return on Equity			10.02%																10.02%
Authorized Return on Equity, Including Incentive Adder			10.52%																10.52%
ATC [Member] | Subsequent Event [Member]
ALLETE's Investment in ATC [Roll Forward]
Cash Investments		$ 0.8
Nobles 2 [Member]
Equity Investments [Line Items]
Ownership Percentage			49.00%																49.00%
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance						$ 163.5													$ 163.5
Equity Earnings	[2]																		(0.6)
Distributed Earnings																			(5.6)
Equity Investment Ending Balance			$ 157.3				$ 163.5												157.3	$ 163.5
Income Statement Data [Abstract]
ALLETE's Equity in Net Income	[2]																		$ (0.6)
Tenaska [Member] | Nobles 2 PPA [Member] | Minnesota Power [Member] | Wind Turbine Generators [Member]
Equity Investments [Line Items]
Generating Capacity Counterparty Owned (MW) | MW			250																250
Contract Term (Years)																			20 years

[1] See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

[2] The Company also recorded net loss attributable to non-controlling interest of $10.6 million related to its investment in Nobles 2

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Equity Investments Equity Investment in Nobles 2 (Details) $ in Millions		12 Months Ended
		Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Equity Investments [Line Items]
Equity Investments		$ 322.7	$ 318.0
Cash Investments		5.9	17.6	$ 99.1
Equity Earnings		18.7	20.0	22.1
Net Loss Attributable to Non-Controlling Interest		(58.0)	(31.4)	(12.6)
Nobles 2 [Member]
Equity Investments [Line Items]
Net Loss Attributable to Non-Controlling Interest		$ 10.6
Nobles 2 [Member]
Equity Investments [Line Items]
Equity Method Investment, Ownership Percentage		49.00%
Equity Investments		$ 157.3	163.5
Equity Earnings	[1]	(0.6)
Distributed Earnings		$ (5.6)
ATC [Member]
Equity Investments [Line Items]
Equity Method Investment, Ownership Percentage		8.00%
Equity Investments		$ 165.4	154.5	149.0
Cash Investments		5.9	0.0
Expected Additional Investment in 2022		8.2
Equity Earnings		19.3	21.3	$ 22.3
Distributed Earnings		$ (15.5)	$ (17.2)
Wind Turbine Generators [Member] | Tenaska [Member] | Minnesota Power [Member] | Nobles 2 PPA [Member]
Equity Investments [Line Items]
Contract Term (Years)		20 years
Generating Capacity Counterparty Owned (MW) | MW		250

[1] The Company also recorded net loss attributable to non-controlling interest of $10.6 million related to its investment in Nobles 2

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Fair Value - Recurring Fair Value Measures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022		Dec. 31, 2021
Liabilities [Abstract]
Debt Securities, Available-for-sale, Maturity, Allocated and Single Maturity Date, within One Year, Fair Value	$ 0.7
Available-for-sale Securities, Debt Maturities, After One Year Through Three Years, Fair Value	2.7
Available-for-sale Securities, Debt Maturities, After Three Years Through Five Years, Fair Value	1.9
Available-for-sale Securities, Debt Maturities, After Five Years, Fair Value	0.4
Recurring Fair Value Measures [Member]
Investments [Abstract]
Available-for-sale – Equity Securities	7.7	[1]	$ 8.9	[2]
Available-for-sale – Corporate and Governmental Debt Securities	5.7	[1],[3]	6.2	[2]
Cash Equivalents	4.2	[1]	2.5	[2]
Total Fair Value of Assets	17.6		17.6
Liabilities [Abstract]
Deferred Compensation	15.0	[4]	18.0	[5]
Total Fair Value of Liabilities	15.0		18.0
Fair Value Hierarchy Transfers, All Levels	0.0		0.0
Recurring Fair Value Measures [Member] | Level 1 [Member]
Investments [Abstract]
Available-for-sale – Equity Securities	7.7	[1]	8.9	[2]
Available-for-sale – Corporate and Governmental Debt Securities	0.0	[1],[3]	0.0	[2]
Cash Equivalents	4.2	[1]	2.5	[2]
Total Fair Value of Assets	11.9		11.4
Liabilities [Abstract]
Deferred Compensation	0.0	[4]	0.0	[5]
Total Fair Value of Liabilities	0.0		0.0
Recurring Fair Value Measures [Member] | Level 2 [Member]
Investments [Abstract]
Available-for-sale – Equity Securities	0.0	[1]	0.0	[2]
Available-for-sale – Corporate and Governmental Debt Securities	5.7	[1],[3]	6.2	[2]
Cash Equivalents	0.0	[1]	0.0	[2]
Total Fair Value of Assets	5.7		6.2
Liabilities [Abstract]
Deferred Compensation	15.0	[4]	18.0	[5]
Total Fair Value of Liabilities	15.0		18.0
Recurring Fair Value Measures [Member] | Level 3 [Member]
Investments [Abstract]
Available-for-sale – Equity Securities	0.0	[1]	0.0	[2]
Available-for-sale – Corporate and Governmental Debt Securities	0.0	[1],[3]	0.0	[2]
Cash Equivalents	0.0	[1]	0.0	[2]
Total Fair Value of Assets	0.0		0.0
Liabilities [Abstract]
Deferred Compensation	0.0	[4]	0.0	[5]
Total Fair Value of Liabilities	$ 0.0		$ 0.0

[1] Included in Other Non-Current Assets on the Consolidated Balance Sheet.

[2] Included in Other Non-Current Assets on the Consolidated Balance Sheet.

[3] As of December 31, 2022, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $2.7 million, in three years to less than five years was $1.9 million and in five or more years was $0.4 million.

[4] Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

[5] Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

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Fair Value - Financial Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Fair Value of Financial Instruments [Line Items]
Short-Term and Long-Term Debt - Carrying Amount	[1]	$ 1,929.1	$ 1,986.4
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Short-Term and Long-Term Debt - Fair Value	[1]	$ 1,782.7	$ 2,192.6

[1] Excludes unamortized debt issuance costs.

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Fair Value - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ 0.0	$ 0.0
Equity Investments	322.7	318.0
Goodwill	154.9
Taconite Harbor [Member] | Resource Package [Member] | MPUC [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Net Book Value	25.0
Boswell Unit 3 [Member] | 2021 Integrated Resource Plan [Member] | MPUC [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Net Book Value	235.0
Boswell Unit 4 [Member] | 2021 Integrated Resource Plan [Member] | MPUC [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Net Book Value	435.0
ATC [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Equity Investments	165.4	154.5	$ 149.0
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] | Corporate and Other [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Impairment of Long-Lived Assets Held-for-use	0.0
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] | ATC [Member] | Regulated Operations [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Equity Method Investment, Indicators of Impairment	$ 0.0	$ 0.0

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Short-Term and Long-Term Debt - Short-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Short-Term Debt - Outstanding	$ 272.6	$ 214.2
Short-Term Debt - Unamortized Debt Issuance Costs	0.1
Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	475.7	432.0
Standby Letters of Credit	32.8	31.5
Draws Outstanding	$ 31.3	$ 159.7

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Short-Term and Long-Term Debt - Long-Term Debt (Details) $ in Millions			12 Months Ended
	Aug. 09, 2022 USD ($)	Feb. 28, 2022 USD ($)	Dec. 31, 2022 USD ($) Years	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Long-Term Debt			$ 1,648.2	$ 1,763.2
Long-Term Debt - Unamortized Debt Issuance Costs			8.2
Debt Instrument [Abstract]
Long-Term Debt Maturing in 2022			91.9
Long-Term Debt Maturing in 2023			94.8
Long-Term Debt Maturing in 2024			386.1
Long-Term Debt Maturing in 2025			79.4
Long-Term Debt Maturing in 2026			122.5
Long-Term Debt Maturing Thereafter			1,154.4
Proceeds from Non-Controlling Interest - Net of Issuance Costs			155.7	$ 90.9	$ 414.5
Camp Ripley Financing [Member]
Debt Instrument [Abstract]
Annual Financing Payment			$ 1.4
Financing Renewal Term (Years) | Years			2
Purchase Option			$ 4.0
First Mortgage Bonds - 2.50% Due August 2030 [Member]
Debt Instrument [Abstract]
Interest Rate			4.08%
First Mortgage Bonds - 4.47% Series Due 2049 [Member]
Debt Instrument [Abstract]
Interest Rate			4.47%
First Mortgage Bonds - 4.07% Series Due 2048 [Member]
Debt Instrument [Abstract]
Interest Rate			4.07%
ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]
Debt Instrument [Abstract]
Interest Rate			3.11%
First Mortgage Bonds - 2.50% Series Due 2030
Debt Instrument [Abstract]
Interest Rate			2.50%
First Mortgage Bonds - 3.30% Series Due 2050
Debt Instrument [Abstract]
Interest Rate			3.30%
March Unsecured Term Loan Due in 2023
Debt Instrument [Abstract]
Unsecured Term Loan, Amount			$ 170.0
Debt Instrument, Description of Variable Rate Basis			SOFR
Debt Instrument, Basis Spread on Variable Rate			0.75%
ALLETE Bonds 4.54% Due August 2032
Debt Instrument [Abstract]
Proceeds from Issuance of First Mortgage Bond	$ 75.0
Interest Rate	4.54%
February Unsecured Term Loan Terminated in April 2022
Debt Instrument [Abstract]
Unsecured Term Loan, Amount		$ 175.0

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Short-Term and Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 1,929.1	$ 1,986.4
Unamortized Debt Issuance Costs		(8.3)	(9.0)
Total Long-Term Debt		1,920.8	1,977.4
Less: Due Within One Year		272.6	214.2
Net Long-Term Debt		$ 1,648.2	1,763.2
First Mortgage Bonds - 4.85% Series Due 2021 [Member]
Debt Instrument [Line Items]
Interest Rate		4.85%
First Mortgage Bonds - 3.02% Series Due 2021 [Member]
Debt Instrument [Line Items]
Interest Rate		3.02%
First Mortgage Bonds - 3.40% Series Due 2022 [Member]
Debt Instrument [Line Items]
Interest Rate		3.40%
Long-term Debt		$ 0.0	75.0
First Mortgage Bonds - 6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Interest Rate		6.02%
Long-term Debt		$ 75.0	75.0
First Mortgage Bonds - 3.69% Series Due 2024 [Member]
Debt Instrument [Line Items]
Interest Rate		3.69%
Long-term Debt		$ 60.0	60.0
First Mortgage Bonds - 4.90% Series Due 2025 [Member]
Debt Instrument [Line Items]
Interest Rate		4.90%
Long-term Debt		$ 30.0	30.0
First Mortgage Bonds - 5.10% Series Due 2025 [Member]
Debt Instrument [Line Items]
Interest Rate		5.10%
Long-term Debt		$ 30.0	30.0
First Mortgage Bonds - 3.20% Series Due 2026 [Member]
Debt Instrument [Line Items]
Interest Rate		3.20%
Long-term Debt		$ 75.0	75.0
First Mortgage Bonds - 5.99% Series Due 2027 [Member]
Debt Instrument [Line Items]
Interest Rate		5.99%
Long-term Debt		$ 60.0	60.0
First Mortgage Bonds - 3.30% Series Due 2028 [Member]
Debt Instrument [Line Items]
Interest Rate		3.30%
Long-term Debt		$ 40.0	40.0
First Mortgage Bonds - 2.50% Due August 2030 [Member]
Debt Instrument [Line Items]
Interest Rate		4.08%
Long-term Debt		$ 70.0	70.0
First Mortgage Bonds - 3.74% Series Due 2029 [Member]
Debt Instrument [Line Items]
Interest Rate		3.74%
Long-term Debt		$ 50.0	50.0
First Mortgage Bonds - 2.50% Series Due 2030
Debt Instrument [Line Items]
Interest Rate		2.50%
Long-term Debt		$ 46.0	46.0
First Mortgage Bonds - 3.86% Series Due 2030 [Member]
Debt Instrument [Line Items]
Interest Rate		3.86%
Long-term Debt		$ 60.0	60.0
First Mortgage Bonds - 2.79% Series Due 2031
Debt Instrument [Line Items]
Interest Rate		2.79%
Long-term Debt		$ 100.0	100.0
First Mortgage Bonds - 5.69% Series Due 2036 [Member]
Debt Instrument [Line Items]
Interest Rate		5.69%
Long-term Debt		$ 50.0	50.0
First Mortgage Bonds - 6.00% Series Due 2040 [Member]
Debt Instrument [Line Items]
Interest Rate		6.00%
Long-term Debt		$ 35.0	35.0
First Mortgage Bonds - 5.82% Series Due 2040 [Member]
Debt Instrument [Line Items]
Interest Rate		5.82%
Long-term Debt		$ 45.0	45.0
First Mortgage Bonds - 4.08% Series Due 2042 [Member]
Debt Instrument [Line Items]
Interest Rate		4.08%
Long-term Debt		$ 85.0	85.0
First Mortgage Bonds - 4.21% Series Due 2043 [Member]
Debt Instrument [Line Items]
Interest Rate		4.21%
Long-term Debt		$ 60.0	60.0
First Mortgage Bonds - 4.95% Series Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate		4.95%
Long-term Debt		$ 40.0	40.0
First Mortgage Bonds - 5.05% Series Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate		5.05%
Long-term Debt		$ 40.0	40.0
First Mortgage Bonds - 4.39% Series Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate		4.39%
Long-term Debt		$ 50.0	50.0
First Mortgage Bonds - 4.07% Series Due 2048 [Member]
Debt Instrument [Line Items]
Interest Rate		4.07%
Long-term Debt		$ 60.0	60.0
First Mortgage Bonds - 4.47% Series Due 2049 [Member]
Debt Instrument [Line Items]
Interest Rate		4.47%
Long-term Debt		$ 30.0	30.0
First Mortgage Bonds - 3.30% Series Due 2050
Debt Instrument [Line Items]
Interest Rate		3.30%
Long-term Debt		$ 94.0	94.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024 [Member]
Debt Instrument [Line Items]
Interest Rate		3.26%
Long-term Debt		$ 19.3	29.1
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt		27.8	27.8
Revolving Credit Facility Variable Rate Due 2025
Debt Instrument [Line Items]
Long-term Debt		$ 13.0	145.0
Unsecured Senior Notes 2.65% Due 2025
Debt Instrument [Line Items]
Interest Rate		2.65%
Long-term Debt		$ 150.0	150.0
ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]
Debt Instrument [Line Items]
Interest Rate		3.11%
Long-term Debt		$ 80.0	80.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Interest Rate		4.15%
Long-term Debt		$ 15.0	15.0
SWL&P First Mortgage Bonds 4.14% Series Due 2048 [Member]
Debt Instrument [Line Items]
Interest Rate		4.14%
Long-term Debt		$ 12.0	12.0
Unsecured Term Loan Variable Rate Due 2022
Debt Instrument [Line Items]
Long-term Debt		0.0	110.0
Other Long-Term Debt, 2.16% – 4.58% Due 2022 – 2051 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 82.0	57.5
Other Long-Term Debt, 2.16% – 4.58% Due 2022 – 2051 [Member] | Weighted Average
Debt Instrument [Line Items]
Interest Rate		4.94%
4.54% Series Due 2032
Debt Instrument [Line Items]
Interest Rate		4.54%
Long-term Debt		$ 75.0	0.0
Unsecured Term Loan Variable Rate Due 2023
Debt Instrument [Line Items]
Long-term Debt		$ 170.0	$ 0.0
March Unsecured Term Loan Due in 2023
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		SOFR
Debt Instrument, Basis Spread on Variable Rate		0.75%

[1] Excludes unamortized debt issuance costs.

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Short-Term and Long-Term Debt - Financial Covenants (Details)	Dec. 31, 2022
Debt Instrument [Line Items]
Actual Indebtedness to Total Capitalization Ratio	0.40
Financial Covenants [Abstract]
Actual Indebtedness to Total Capitalization Ratio	0.40
Maximum [Member]
Debt Instrument [Line Items]
Allowed Indebtedness to Total Capitalization Ratio	0.65
Financial Covenants [Abstract]
Allowed Indebtedness to Total Capitalization Ratio	0.65

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Commitments, Guarantees and Contingencies Minimum Payments for Certain Long-Term Commitments (Details) $ in Millions	Dec. 31, 2022 USD ($)
Capital Purchase Obligations [Member]
Minimum Annual Payments for Certain Long-Term Commitments [Line Items]
Minimum Payments in 2023	$ 26.6
Minimum Payments in 2024	10.6
Minimum Payments in 2025	1.3
Minimum Payments in 2026	2.7
Minimum Payments in 2027	0.0
Minimum Payments Thereafter	0.6
Easements [Member]
Minimum Annual Payments for Certain Long-Term Commitments [Line Items]
Minimum Payments in 2023	7.8	[1]
Minimum Payments in 2024	7.9	[1]
Minimum Payments in 2025	8.0	[1]
Minimum Payments in 2026	8.1	[1]
Minimum Payments in 2027	8.2	[1]
Minimum Payments Thereafter	206.9	[1]
PPAs [Member]
Minimum Annual Payments for Certain Long-Term Commitments [Line Items]
Minimum Payments in 2023	151.3	[2]
Minimum Payments in 2024	145.8	[2]
Minimum Payments in 2025	137.0	[2]
Minimum Payments in 2026	136.9	[2]
Minimum Payments in 2027	123.6	[2]
Minimum Payments Thereafter	1,010.3	[2]
Long-Term Service Agreements [Member]
Minimum Annual Payments for Certain Long-Term Commitments [Line Items]
Minimum Payments in 2023	49.9	[3]
Minimum Payments in 2024	10.2	[3]
Minimum Payments in 2025	6.5	[3]
Minimum Payments in 2026	0.0	[3]
Minimum Payments in 2027	0.0	[3]
Minimum Payments Thereafter	$ 0.0	[3]

[1] Easement obligations represent the minimum payments for our land easement agreements at our wind energy facilities.

[2] Does not include 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.)

[3] Consists of long-term service agreements for wind energy facilities and minimum purchase commitments under coal and rail contracts.

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Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Square Butte [Member] | Square Butte PPA (expires 2026) [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Total Debt Outstanding | $	$ 210.2
Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Capacity Counterparty Owned (MW)	455
Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Cost of Purchased Power | $	$ 82.7	$ 82.4	$ 79.5
Pro Rata Share of PPA Counterparty Interest Expense | $	$ 5.1	$ 5.8	$ 7.1
Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Minnesota Power Output Entitlement (Percent)	50.00%
PPA Annual Debt Service Obligation (Percentage)	50.00%
Nobles 2 [Member] | Nobles 2 [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased - Electric Energy and Capacity (MW)	250
Oliver Wind [Member] | Oliver Wind I PPA [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased - Electric Energy (MW)	50
Oliver Wind [Member] | Oliver Wind II PPA [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased - Electric Energy (MW)	48
Minnkota Power [Member] | Square Butte PPA (expires 2026) [Member] | Minnkota Sales Agreement [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Minnesota Power Output Entitlement (Percent)	32.00%	28.00%	28.00%
Silver Bay Power [Member] | Minnesota Power [Member] | Silver Bay Power Self-Generation [Member]
Power Purchase Agreements [Line Items]
Energy Generation Owned (MW)	90
Calpine Corporation [Member] | Calpine Corporation PPA [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased - Electric Capacity (MW)	25
Great River Energy [Member] | Great River Energy Power Sales Agreement (expires May 2025) | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Sold Electric - Capacity (MW)	100
Basin [Member] | Basin Power Sales Agreement (expires May 2028) [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Sold Electric - Capacity (MW)	100
Oconto Electric Cooperative [Member] | Oconto Electric Cooperative Power Sales Agreement [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Sold Electric - Energy and Capacity (MW)	25
Basin Electric Power Cooperative [Member] | Basin Electric Cooperative PSA June 2022 - May 2023 [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Sold Electric - Capacity (MW)	75
Basin Electric Power Cooperative [Member] | Basin Electric Cooperative PSA June 2023 - May 2025 [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Sold Electric - Capacity (MW)	125
Manitoba Hydro [Member] | Manitoba Hydro PPA (expires 2040) [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased - Electric Energy (MW)	133
Manitoba Hydro [Member] | Manitoba Hydro PPA (expires May 2035) [Member] | Minnesota Power [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased - Electric Energy and Capacity (MW)	250
2024-01-01 [Member] | Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Annual Debt Service through 2026 | $	$ 32.2
2025-01-01 [Member] | Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Annual Debt Service through 2026 | $	28.4
2026-01-01 | Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Annual Debt Service through 2026 | $	28.6
2023-01-01 [Member] | Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member] | Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Annual Debt Service through 2026 | $	$ 47.2

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Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Coal Combustion Residuals [Member] | Minnesota Power [Member]
Environmental Matters [Line Items]
Expected Period for Costs of Compliance	15 years
Coal Combustion Residuals [Member] | Minimum [Member] | Minnesota Power [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	$ 65.0
Coal Combustion Residuals [Member] | Maximum [Member] | Minnesota Power [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	120.0
Manufactured Gas Plant [Member] | SWL&P [Member] | Superior, WI [Member]
Environmental Matters [Line Items]
Environmental Remediation Liability	$ 14.9

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Commitments, Guarantees and Contingencies - Other Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
South Shore Energy | Letters of Credit [Member]
Guarantor Obligations [Line Items]
Standby Letters of Credit	$ 23.9
New Energy | Letters of Credit [Member]
Guarantor Obligations [Line Items]
Standby Letters of Credit	4.2
BNI Energy Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	82.1
BNI Energy Reclamation Liability [Member] | Surety Bonds [Member]
Guarantor Obligations [Line Items]
Collateral	82.4
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	1.0
ALLETE Properties Development and Maintenance Obligations [Member] | Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	2.0
Town Center District Capital Improvement Bonds [Member]
Guarantor Obligations [Line Items]
Bonds	$ 26.4
Bond Term (Years)	31 years
Ownership Percentage of Benefited Property	42.00%	30.00%
Annual Assessment	$ 1.3
Bond Interest Rate	6.00%
ALLETE, Inc. [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
Standby Letters of Credit	$ 290.3
Regulated Operations [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
Standby Letters of Credit	28.2
ALLETE Clean Energy [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
Standby Letters of Credit	222.3
ALLETE South Wind [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
Standby Letters of Credit	$ 11.7

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Common Stock and Earnings Per Share - Summary of Common Stock (Details) - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
	Apr. 05, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Summary of Common Stock [Line Items]
Balance, Shares		57,200	53,200
Stock Issued During Period, Shares, New Issues	3,700
Common Stock Issued	$ 224,000
Common Stock [Member]
Summary of Common Stock [Line Items]
Balance, Shares		57,237	53,220	52,085	51,679
Balance, Equity		$ 1,781,500	$ 1,536,700	$ 1,460,900	$ 1,436,700
Employee Stock Purchase Plan, Shares		11	17	13
Employee Stock Purchase Plan, Equity		$ 900	$ 800	$ 700
Invest Direct, Shares		244	263	309
Invest Direct, Equity		$ 14,900	$ 17,500	$ 18,300
Share-Based Compensation - Shares		82	73	84
Share-Based Compensation - Equity		$ 5,300	$ 6,500	$ 5,200
Equity Issuance Program, Shares			782	0
Equity Issuance Program Shares Authorized				13,600
Equity Issuance Program Shares Available for Issuance		2,100
Stock Issued During Period, Shares, New Issues		3,680
Common Stock Issued			$ 51,000
Common Stock Issued		$ 223,700
Common Stock [Member] | PIE Shares
Summary of Common Stock [Line Items]
Equity Issuance Program, Shares		0	800	0
Common Stock Issued			$ 51,000

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Common Stock and Earnings Per Share - Reconciliation of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	[1]	Sep. 30, 2020	[1]	Jun. 30, 2020	[1]	Mar. 31, 2020	[1]	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 51.7	$ 33.7	$ 37.6	$ 66.3	$ 61.9	$ 27.6	$ 27.9	$ 51.8	$ 38.3		$ 40.7		$ 20.1		$ 66.3		$ 189.3	$ 169.2	$ 165.4
Average Common Shares																	55.9	52.4	51.9
Earnings Per Share	$ 0.90	$ 0.59	$ 0.67	$ 1.24	$ 1.18	$ 0.53	$ 0.53	$ 0.99	$ 0.74		$ 0.78		$ 0.39		$ 1.28		$ 3.38	$ 3.23	$ 3.18
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE																	$ 189.3	$ 169.2	$ 165.4
Average Common Shares																	56.0	52.5	51.9
Earnings Per Share	$ 0.90	$ 0.59	$ 0.67	$ 1.24	$ 1.18	$ 0.53	$ 0.53	$ 0.99	$ 0.73		$ 0.78		$ 0.39		$ 1.28		$ 3.38	$ 3.23	$ 3.18
Dilutive Securities (Shares)																	0.1	0.1	0.0

[1] See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

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Income Tax Expense (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current Income Tax Expense [Abstract]
Federal	[1]	$ 1.2	$ 0.0	$ 0.0
State	[1]	6.1	0.0	0.0
Total Current Income Tax Expense	[1]	7.3	0.0	0.0
Deferred Income Tax Expense (Benefit) [Abstract]
Federal	[2]	(32.8)	(37.2)	(51.5)
State	[3]	(5.2)	10.8	8.6
Investment Tax Credit Amortization		(0.5)	(0.5)	(0.5)
Total Deferred Income Tax Expense (Benefit)		(38.5)	(26.9)	(43.4)
Total Income Tax Expense (Benefit)		$ (31.2)	$ (26.9)	$ (43.4)

[1] For the years ended December 31, 2021 and 2020, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of certain tax legislation. Federal and state NOLs are being carried forward to offset current and future taxable income. For the year ended December 31, 2022, federal NOLs were fully utilized and production tax credits were used to partially offset federal taxable income.

[2] For the years ended December 31, 2022, 2021 and 2020, the federal tax benefit is primarily due to production tax credits.

[3] For the year ended December 31, 2022, the state impact includes the benefit of deferred repricing as a result of the New Energy acquisition

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Income Tax Expense - Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Abstract]
Income Before Non-Controlling Interest and Income Taxes		$ 100.1	$ 110.9	$ 109.4
Statutory Federal Income Tax Rate		21.00%	21.00%	21.00%
Income Taxes Computed at Statutory Federal Rate		$ 21.0	$ 23.3	$ 23.0
Increase (Decrease) in Tax Due to: [Abstract]
State Income Taxes – Net of Federal Income Tax Benefit		8.6	8.6	6.5
Effective Income Tax Rate Reconciliation, Deferred Revaluation - Net of Federal Income Tax Benefit		(7.9)	0.0	0.0
Production Tax Credits		(50.7)	(53.5)	(62.7)
Effective income Tax Rate Reconciliation - Investment Tax Credits		(4.1)	0.0	0.0
Regulatory Differences – Excess Deferred Tax Benefit	[1]	(9.1)	(9.5)	(9.9)
Non-controlling interest		11.2	6.3	2.7
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Payment Arrangement, Amount		(1.1)	(1.0)	(0.8)
Other		0.9	(1.1)	(2.2)
Total Income Tax Expense (Benefit)		$ (31.2)	$ (26.9)	$ (43.4)
Effective Tax Rate		(31.20%)	(24.30%)	(39.70%)

[1] 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.)

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Income Tax Expense - Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Deferred Income Tax Assets [Abstract]
Employee Benefits and Compensation		$ 46.4	$ 44.5
Property Related		61.9	54.8
NOL Carryforwards		16.7	67.5
Deferred Tax Assets, Capital Loss Carryforwards		13.1	0.0
Tax Credit Carryforwards		548.7	509.1
Power Sales Agreements		13.7	16.5
Regulatory Liabilities		95.5	101.5
Other		28.1	18.0
Gross Deferred Income Tax Assets		824.1	811.9
Deferred Income Tax Asset Valuation Allowance		(60.2)	(69.0)
Total Deferred Income Tax Assets		763.9	742.9
Deferred Income Tax Liabilities [Abstract]
Property-Related		661.7	680.8
Regulatory Assets for Benefit Obligations		57.7	54.9
Unamortized Investment Tax Credits		30.0	30.5
Partnership Basis Differences		126.0	106.3
Regulatory Assets		10.7	14.3
Other		28.0	30.0
Total Deferred Income Tax Liabilities		922.0	924.7
Net Deferred Income Taxes	[1]	158.1	181.8
Deferred Tax Liabilities - Deferred Gain		$ 7.9	$ 7.9

[1] Recorded as a net Deferred Income Tax liability on the Consolidated Balance Sheet.

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Income Tax Expense - NOL and Tax Credit Carryforwards (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Federal [Member]
NOL and Tax Credit Carryforwards [Line Items]
NOL Carryforwards	[1]	$ 0.0	$ 177.3
Tax Credit Carryforwards		464.5	416.4
Federal Capital Loss	[1]	35.1	0.0
Tax Credit Carryforwards, Valuation Allowance		0.0
NOL Carryforwards, Valuation Allowance		0.0
State [Member]
NOL and Tax Credit Carryforwards [Line Items]
NOL Carryforwards	[1]	323.0	506.9
Tax Credit Carryforwards	[2]	24.5	24.2
State Capital Loss	[1]	83.2	0.0
Tax Credit Carryforwards, Valuation Allowance		$ 59.6	$ 68.6

[1] Pre-tax amounts.

[2] Net of a $59.6 million valuation allowance as of December 31, 2022 ($68.6 million as of December 31, 2021).

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Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 1.3	$ 1.4	$ 1.4
Additions for Tax Positions Related to the Current Year	0.0	0.0	0.1
Reduction for Tax Positions Related to Prior Years	0.0	(0.1)	(0.1)
Balance as of December 31	1.3	1.3	1.4
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.6
Unrecognized Tax Benefits, Accrued Interest		0.0	0.0
Unrecognized Tax Benefits, Penalties	0.0	$ 0.0	$ 0.0
Material Changes to Unrecognized Tax Benefits Expected During Next 12 Months	$ 0.0

XML

Pension and Other Postretirement Benefit Plans - Contributions (Details) - USD ($) shares in Thousands, $ in Millions			12 Months Ended
		Jan. 17, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
ESOP Compensation Expense			$ 12.0	$ 11.5	$ 11.2
Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer		$ 6.5
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Shares					0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Cash			$ 0.0	10.3	$ 10.7
Defined Benefit Plan - Amendments			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.
Expected Employer Contributions in 2022			$ 0.0
Defined Benefit Plan, Plan Assets, Contributions by Employer	[1]		12.3	19.7
Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Employer Contributions in 2022			0.0
Defined Benefit Plan, Plan Assets, Contributions by Employer			0.3	0.7
Postretirement Health and Life [Member] | VEBA [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Other Postretirement Benefit Plans			0.0	0.0	0.0
Postretirement Health and Life [Member] | Irrevocable Grantor Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Other Postretirement Benefit Plans			$ 0.0	$ 0.0	$ 0.0

[1] Includes Participant Contributions noted above, any contributions made by the Company to pension plan trusts and any direct benefit payments made under certain plans.(c)    Presented here net of amounts related to prepaid pension for SWL&P that are reclassified to Regulatory Assets on the Consolidated Balance Sheet.

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Pension and Other Postretirement Benefit Plans - Obligation and Funded Status (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Change in Plan Assets [Roll Forward]
Non-Current Liabilities		$ (179.7)	$ (179.5)
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Loss	[1]	9.2	12.7
Change in Benefit Obligation [Roll Forward]
Obligation, Beginning of Year		148.2	167.6
Service Cost		3.0	3.6	$ 3.3
Interest Cost	[2]	4.4	4.4	5.0
Actuarial (Gain) Loss	[3]	(38.7)	(19.7)
Benefits Paid		(9.2)	(10.6)
Participant Contributions		2.7	2.9
Obligation, End of Year		110.4	148.2	167.6
Change in Plan Assets [Roll Forward]
Fair Value, Beginning of Year		201.8	186.0
Actual Return on Plan Assets		(33.0)	22.8
Employer Contribution		0.3	0.7
Defined Benefit Plan Contributions by Plan Participants, Excluding Key Employees		2.7	2.9
Benefits Paid		(9.2)	(10.6)
Fair Value, End of Year		162.6	201.8	186.0
Funded Status, End of Year		52.2	53.6
Non-Current Assets		58.8	64.8
Current Liabilities		(0.2)	(1.4)
Non-Current Liabilities		(6.4)	(9.8)
Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Loss		(260.2)	(260.2)
Accumulated Benefit Obligation		724.5	875.5
Change in Benefit Obligation [Roll Forward]
Obligation, Beginning of Year		911.7	965.7
Service Cost		9.3	11.0	10.7
Interest Cost	[4]	27.2	24.6	27.9
Plan Amendments		0.8	0.0
Actuarial (Gain) Loss	[5]	(160.6)	(39.0)
Benefits Paid		(58.9)	(56.5)
Participant Contributions		10.2	7.3
Plan Curtailments		0.0	(1.4)
Obligation, End of Year		739.7	911.7	965.7
Change in Plan Assets [Roll Forward]
Fair Value, Beginning of Year		745.7	759.4
Actual Return on Plan Assets		(130.5)	23.1
Employer Contribution	[6]	12.3	19.7
Benefits Paid		(58.9)	(56.5)
Fair Value, End of Year		568.6	745.7	$ 759.4
Funded Status, End of Year		(171.1)	(166.0)
Current Liabilities		(2.1)	(2.1)
Non-Current Liabilities		$ (169.0)	$ (163.9)

[1] Excludes gains, losses and contributions associated with irrevocable grantor trusts.

[2] 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.

[3] Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

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

[5] Actuarial gain was primarily the result of increases in discount rates in 2022 and 2021.

[6] Includes Participant Contributions noted above, any contributions made by the Company to pension plan trusts and any direct benefit payments made under certain plans.(c)    Presented here net of amounts related to prepaid pension for SWL&P that are reclassified to Regulatory Assets on the Consolidated Balance Sheet.

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Pension and Other Postretirement Benefit Plans - Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	[1]	$ 9.2	$ 12.7
Prior Service Credit		(13.2)	(20.7)
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)		29.8	20.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet		52.2	53.6
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss		(260.2)	(260.2)
Prior Service Credit		0.1	1.0
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)		89.0	93.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet		(171.1)	(166.0)
Trust for Benefit of Employees [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Long-term Investments		$ 11.8	$ 13.2

[1] Excludes gains, losses and contributions associated with irrevocable grantor trusts.

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Pension and Other Postretirement Benefit Plans - Components of Net Periodic Expense (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost		$ 3.0	$ 3.6	$ 3.3
Interest Cost	[1]	4.4	4.4	5.0
Expected Return on Plan Assets	[1]	(9.6)	(9.9)	(9.7)
Amortization of Loss	[1]	0.4	3.0	1.0
Amortization of Prior Service Cost	[1]	(7.5)	(7.6)	(8.0)
Effect of Plan Curtailment	[1]	0.0	0.0	(0.3)
Net Pension Cost		(9.3)	(6.5)	(8.7)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost		9.3	11.0	10.7
Interest Cost	[2]	27.2	24.6	27.9
Expected Return on Plan Assets	[2]	(41.5)	(43.4)	(42.7)
Amortization of Loss	[2]	11.4	18.8	12.8
Amortization of Prior Service Cost	[2]	(0.1)	(0.2)	(0.2)
Net Pension Cost		$ 6.3	$ 10.8	$ 8.5

[1] 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.

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

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Pension and Other Postretirement Benefit Plans - Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ 3.9	$ (32.7)
Amortization of Prior Service Cost	7.5	7.6
Amortization of Loss	(0.4)	(3.0)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	11.0	(28.1)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	11.4	(20.1)
Amortization of Prior Service Cost	0.1	0.2
Prior Service Credit Arising During the Period	0.8	0.0
Amortization of Loss	(11.4)	(18.8)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$ 0.9	$ (38.7)

XML

Pension and Other Postretirement Benefit Plans - Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - Pension [Member] - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 739.7	$ 911.7
Accumulated Benefit Obligation	724.5	875.5
Fair Value of Plan Assets	$ 568.6	$ 745.7

XML

Pension and Other Postretirement Benefit Plans - Unrecognized Postretirement Health and Life Costs (Details) - Postretirement Health and Life [Member] - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	[1]	$ (9.2)	$ (12.7)
Prior Service Credit		(13.2)	(20.7)
Total Unrecognized Postretirement Health and Life Cost		$ (22.4)	$ (33.4)

[1] Excludes gains, losses and contributions associated with irrevocable grantor trusts.

XML

Pension and Other Postretirement Benefit Plans - Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet (Details) - Postretirement Health and Life [Member] - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	[1]	$ 9.2	$ 12.7
Prior Service Credit		13.2	20.7
Accumulated Net Periodic Benefit Cost in Excess of Contributions		29.8	20.2
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet		$ 52.2	$ 53.6

[1] Excludes gains, losses and contributions associated with irrevocable grantor trusts.

XML

Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2022 USD ($)
Pension [Member]
Estimated Future Benefit Payments [Abstract]
2022	$ 58.0
2023	58.4
2024	58.0
2025	57.3
2026	57.0
Years 2027 - 2031	274.9
Postretirement Health and Life [Member]
Estimated Future Benefit Payments [Abstract]
2022	7.2
2023	7.5
2024	7.5
2025	7.7
2026	8.0
Years 2027 - 2031	$ 42.4

XML

Pension and Other Postretirement Benefit Plans - Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	5.70%	3.05%
Rate of Compensation Increase	3.58%	3.58%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.28%	2.87%	3.52%
Expected Long-Term Return on Plan Assets	6.00%	6.50%	6.75%
Rate of Compensation Increase	3.58%	3.62%	4.06%
Postretirement Health and Life [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	5.68%	3.09%
Health Care Trend Rates [Abstract]
Trend Rate	6.50%	5.66%
Ultimate Trend Rate	5.00%	4.50%
Year Ultimate Trend Rate Effective	2038	2038
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.09%	2.70%	3.45%
Expected Long-Term Return on Plan Assets	5.41%	5.85%	6.08%

XML

Pension and Other Postretirement Benefit Plans - Plan Asset Allocations (Details) - shares shares in Millions		Dec. 31, 2022	Dec. 31, 2021
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations		100.00%	100.00%
ALLETE Common Stock Included in Pension Plan Equity Securities (Shares)		0.0	0.0
Plan Asset Target Allocations		100.00%
Pension [Member] | Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations		46.00%	49.00%
Plan Asset Target Allocations		49.00%
Pension [Member] | Fixed Income [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations		50.00%	48.00%
Plan Asset Target Allocations		50.00%
Pension [Member] | Private Equity [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations		0.00%	0.00%
Pension [Member] | Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations		4.00%	3.00%
Plan Asset Target Allocations		1.00%
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations	[1]	100.00%	100.00%
Plan Asset Target Allocations	[2]	100.00%
Postretirement Health and Life [Member] | Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations	[1]	66.00%	70.00%
Plan Asset Target Allocations	[2]	65.00%
Postretirement Health and Life [Member] | Fixed Income [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations	[1]	34.00%	29.00%
Plan Asset Target Allocations	[2]	35.00%
Postretirement Health and Life [Member] | Private Equity [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations	[1]	0.00%	1.00%
Postretirement Health and Life [Member] | Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual Plan Asset Allocations	[1]	0.00%	0.00%
Plan Asset Target Allocations	[2]	0.00%

[1] Includes VEBAs and irrevocable grantor trusts.

[2] Includes VEBAs and irrevocable grantor trusts.

XML

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures (Details) - USD ($) $ in Millions	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Pension [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	$ 568.6		$ 745.7		$ 759.4
Pension [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	134.3		12.2
Pension [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	411.9		711.9
Pension [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	22.4		21.6
Pension [Member] | U.S. Large-cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	61.2	[1]	113.8	[2]
Pension [Member] | U.S. Large-cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | U.S. Large-cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	61.2	[1]	113.8	[2]
Pension [Member] | U.S. Large-cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | U.S. Mid-cap Growth [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	40.0	[1]	47.6	[2]
Pension [Member] | U.S. Mid-cap Growth [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | U.S. Mid-cap Growth [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	40.0	[1]	47.6	[2]
Pension [Member] | U.S. Mid-cap Growth [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | U.S. Small-cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	35.4	[1]	46.2	[2]
Pension [Member] | U.S. Small-cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | U.S. Small-cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	35.4	[1]	46.2	[2]
Pension [Member] | U.S. Small-cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | International [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	127.0		158.2
Pension [Member] | International [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	127.0		0.0
Pension [Member] | International [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		158.2
Pension [Member] | International [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Pension [Member] | Fixed Income [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	275.3	[1]	346.1	[2]
Pension [Member] | Fixed Income [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | Fixed Income [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	275.3	[1]	346.1	[2]
Pension [Member] | Fixed Income [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[1]	0.0	[2]
Pension [Member] | Cash and Cash Equivalents [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	7.3		12.2
Pension [Member] | Cash and Cash Equivalents [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	7.3		12.2
Pension [Member] | Cash and Cash Equivalents [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Pension [Member] | Cash and Cash Equivalents [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Pension [Member] | Private Equity [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			0.0		7.0
Pension [Member] | Real Estate [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	22.4		21.6
Pension [Member] | Real Estate [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Pension [Member] | Real Estate [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Pension [Member] | Real Estate [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	22.4		21.6		18.0
Postretirement Health and Life [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	162.6		201.8		186.0
Postretirement Health and Life [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	162.6		198.0
Postretirement Health and Life [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		1.8
Postretirement Health and Life [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		2.0
Postretirement Health and Life [Member] | U.S. Large-cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	26.7	[3]	40.1	[4]
Postretirement Health and Life [Member] | U.S. Large-cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	26.7	[3]	40.1	[4]
Postretirement Health and Life [Member] | U.S. Large-cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | U.S. Large-cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	25.5	[3]	37.3	[4]
Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	25.5	[3]	37.3	[4]
Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | U.S. Small-cap [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	12.7	[3]	19.3	[4]
Postretirement Health and Life [Member] | U.S. Small-cap [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	12.7	[3]	19.3	[4]
Postretirement Health and Life [Member] | U.S. Small-cap [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | U.S. Small-cap [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | International [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	41.5	[3]	43.7	[4]
Postretirement Health and Life [Member] | International [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	41.5	[3]	43.7	[4]
Postretirement Health and Life [Member] | International [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | International [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0	[3]	0.0	[4]
Postretirement Health and Life [Member] | Mutual Funds [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	55.5		56.7
Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	55.5		56.7
Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Postretirement Health and Life [Member] | Fixed Income [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			1.8
Postretirement Health and Life [Member] | Fixed Income [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			0.0
Postretirement Health and Life [Member] | Fixed Income [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			1.8
Postretirement Health and Life [Member] | Fixed Income [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			0.0
Postretirement Health and Life [Member] | Cash and Cash Equivalents [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.7		0.9
Postretirement Health and Life [Member] | Cash and Cash Equivalents [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.7		0.9
Postretirement Health and Life [Member] | Cash and Cash Equivalents [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Postretirement Health and Life [Member] | Cash and Cash Equivalents [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	0.0		0.0
Postretirement Health and Life [Member] | Private Equity [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			2.0
Postretirement Health and Life [Member] | Private Equity [Member] | Level 1 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			0.0
Postretirement Health and Life [Member] | Private Equity [Member] | Level 2 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets			0.0
Postretirement Health and Life [Member] | Private Equity [Member] | Level 3 [Member]
Recurring Fair Value Measures [Line Items]
Fair Value of Assets	$ 0.0		$ 2.0		$ 1.7

[1] The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity and fixed income securities indexes.

[2] The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity and fixed income securities indexes.

[3] The underlying investments consist of mutual funds (Level 1). 

[4] The underlying investments consist of mutual funds (Level 1). 

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Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures, Activity in Level 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Pension [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	$ 745.7	$ 759.4
Fair Value, End of Year	568.6	745.7
Pension [Member] | Level 3 [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	21.6
Fair Value, End of Year	22.4	21.6
Pension [Member] | Private Equity [Member] | Level 3 [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	0.0	7.0
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Still Held		(3.5)
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Purchase, Sale, and Settlement		(3.5)
Fair Value, End of Year		0.0
Pension [Member] | Real Estate [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	21.6
Fair Value, End of Year	22.4	21.6
Pension [Member] | Real Estate [Member] | Level 3 [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	21.6	18.0
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Still Held	1.0	3.6
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Purchase, Sale, and Settlement	(0.2)	0.0
Fair Value, End of Year	22.4	21.6
Postretirement Health and Life [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	201.8	186.0
Fair Value, End of Year	162.6	201.8
Postretirement Health and Life [Member] | Level 3 [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	2.0
Fair Value, End of Year	0.0	2.0
Postretirement Health and Life [Member] | Private Equity [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	2.0
Fair Value, End of Year		2.0
Postretirement Health and Life [Member] | Private Equity [Member] | Level 3 [Member]
Activity in Level 3 [Roll Forward]
Fair Value, Beginning of Year	2.0	1.7
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Still Held	(1.5)	0.8
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Purchase, Sale, and Settlement	(0.5)	(0.5)
Fair Value, End of Year	$ 0.0	$ 2.0

XML

Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Employee Stock Ownership Plan [Abstract]
ESOP Compensation Expense	$ 12.0	$ 11.5	$ 11.2

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Employee Stock and Incentive Plans - Stock-Based Compensation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2022 shares
Performance Shares [Member]
Stock-based Compensation [Line Items]
Vesting Period (Years)	3 years
Restricted Stock Units [Member]
Stock-based Compensation [Line Items]
Vesting Period (Years)	3 years
Employee Stock Purchase Plan (ESPP) [Member]
Stock-based Compensation [Line Items]
ESPP Discount	5.00%
Executive Long-Term Incentive Compensation Plan [Member]
Stock-based Compensation [Line Items]
Common Stock Reserved (Shares)	0.8
Shares Available for Issuance	0.6

XML

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 1.6	$ 3.0	$ 3.1
Income Tax Benefit	0.5	0.9	0.9
Capitalized Share-Based Compensation Costs	$ 0.0	0.0	0.0
Performance Shares [Member]
Share-Based Compensation Expense [Line Items]
Performance Period (Years)	3 years
Share-Based Compensation Expense	$ 0.7	2.0	2.2
Unrecognized Compensation Cost	$ 1.9
Weighted-Average Period for Recognition (Years/Months)	1 year 8 months 12 days
Restricted Stock Units [Member]
Share-Based Compensation Expense [Line Items]
Performance Period (Years)	3 years
Share-Based Compensation Expense	$ 0.9	$ 1.0	$ 0.9
Unrecognized Compensation Cost	$ 0.8
Weighted-Average Period for Recognition (Years/Months)	1 year 7 months 6 days

XML

Employee Stock and Incentive Plans - Performance Shares and Restricted Stock Units (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
		Feb. 28, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Performance Shares [Member]
Stock-based Compensation [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition			1 year 8 months 12 days
Number of Shares [Rollforward]
As of January 1			80,661	85,284	99,585
Granted	[1]		37,731	33,304	25,763
Awarded			0	0	(25,304)
Unearned Grant Award			(50,524)	(33,375)	(13,625)
Forfeited			(7,379)	(4,552)	(1,135)
As of December 31			60,489	80,661	85,284
Performance Period (Years)			3 years
Weighted-Average Grant Date Fair Value [Abstract]
As of January 1			$ 75.80	$ 80.73	$ 72.78
Granted	[1]		67.22	73.25	83.17
Awarded			0	0	62.03
Unearned Grant Award			77.49	86.09	62.03
Forfeited			71.00	74.05	79.81
As of December 31			$ 69.62	$ 75.80	$ 80.73
Restricted Stock Units [Member]
Stock-based Compensation [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition			1 year 7 months 6 days
Number of Shares [Rollforward]
As of January 1			28,141	37,482	39,943
Granted	[2]		15,477	16,251	15,169
Awarded			(7,396)	(23,631)	(17,193)
Forfeited			(2,658)	(1,961)	(437)
As of December 31			33,564	28,141	37,482
Performance Period (Years)			3 years
Weighted-Average Grant Date Fair Value [Abstract]
As of January 1			$ 73.16	$ 77.64	$ 69.30
Granted	[2]		63.70	64.97	83.48
Awarded			75.55	74.53	63.41
Forfeited			66.44	74.52	77.52
As of December 31			$ 68.80	$ 73.16	$ 77.64
Subsequent Event [Member] | Performance Shares [Member]
Number of Shares [Rollforward]
Granted		51,000
Awarded		0
Performance Period (Years)		3 years
Granted, Grant Date Fair Value		$ 3.4
Subsequent Event [Member] | Restricted Stock Units [Member]
Number of Shares [Rollforward]
Granted		14,700
Awarded		(8,500)
Granted, Grant Date Fair Value		$ 0.9
Awarded, Grant Date Fair Value		$ 0.7

[1] Shares granted include accrued dividends.

[2] Shares granted include accrued dividends.

XML

Business Segment (Details) $ in Millions		3 Months Ended																12 Months Ended
		Dec. 31, 2022 USD ($)	Sep. 30, 2022 USD ($)	Jun. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	[1]	Sep. 30, 2020 USD ($)	[1]	Jun. 30, 2020 USD ($)	[1]	Mar. 31, 2020 USD ($)	[1]	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments																		2	3
Revenue		$ 425.8	$ 388.3	$ 373.1	$ 383.5	$ 399.0	$ 345.4	$ 335.6	$ 339.2	$ 320.4		$ 293.9		$ 243.2		$ 311.6		$ 1,570.7	$ 1,419.2	$ 1,169.1
Other – Non-utility																		7.6	11.4	11.3
Net Income Attributable to ALLETE		51.7	$ 33.7	$ 37.6	$ 66.3	61.9	$ 27.6	$ 27.9	$ 51.8	$ 38.3		$ 40.7		$ 20.1		$ 66.3		189.3	169.2	165.4
Depreciation, Depletion and Amortization																		242.2	231.7	217.8
Impairment of Property, Plant and Equipment																		0.0	0.0	12.7
Interest Expense																		75.2	69.1	65.6
Equity Earnings																		18.7	20.0	22.1
Income Tax Expense (Benefit)																		(31.2)	(26.9)	(43.4)
Assets		6,845.6				6,422.3												6,845.6	6,422.3
Property, Plant and Equipment, Additions																		208.1	476.4
New Energy
Segment Reporting Information [Line Items]
Business Combination, Acquisition Related Costs																		2.7
Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Interest Expense	[2]																	$ (4.8)	(2.9)	(8.3)
Regulated Operations [Member]
Segment Reporting Information [Line Items]
Number of Operating Segments																		3
Depreciation, Depletion and Amortization																		$ 171.9	170.7	166.9
Interest Expense	[2]																	58.1	57.3	58.5
Equity Earnings																		19.3	21.3	22.3
Income Tax Expense (Benefit)																		(10.4)	(16.6)	(19.4)
Property, Plant and Equipment, Additions																		158.3	166.8
Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue																		1,259.3	1,227.9	987.3
Net Income Attributable to ALLETE	[3]																	149.9	129.1	136.3
Assets		4,291.4				4,289.4												$ 4,291.4	4,289.4
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Number of Operating Segments																		3
Revenue																		$ 193.1	104.4	102.2
Net Income Attributable to ALLETE	[3],[4],[5]																	23.1	13.8	8.0
Depreciation, Depletion and Amortization																		11.7	11.8	13.0
Interest Expense	[2]																	19.6	13.2	13.2
Equity Earnings																		(0.6)	(1.3)	(0.2)
Income Tax Expense (Benefit)																		(5.4)	6.3	(1.0)
Assets		680.9				426.2												680.9	426.2
Property, Plant and Equipment, Additions																		47.6	39.7
Purchase Price Accounting - After Tax																		8.3
Corporate and Other [Member] | New Energy
Segment Reporting Information [Line Items]
Business Combination, Acquisition Related Costs																		2.7
Corporate and Other [Member] | Nemadji Trail Energy Center [Member] | South Shore Energy
Segment Reporting Information [Line Items]
Gain on Sale After Tax																			8.5
ALLETE Clean Energy [Member]
Segment Reporting Information [Line Items]
Revenue																		118.3	86.9	79.6
Net Income Attributable to ALLETE	[3]																	16.3	26.3	21.1
Depreciation, Depletion and Amortization																		58.6	49.2	37.9
Impairment of Property, Plant and Equipment																		0.0	0.0	12.7
Interest Expense	[2]																	2.3	1.5	2.2
Income Tax Expense (Benefit)																		(15.4)	(16.6)	(23.0)
Assets		$ 1,873.3				$ 1,706.7												1,873.3	1,706.7
Property, Plant and Equipment, Additions																		2.2	269.9
Residential [Member] | Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		175.9	160.8	140.7
Commercial [Member] | Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		187.2	168.6	139.5
Municipal [Member] | Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		40.2	52.0	41.2
Industrial [Member] | Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		589.0	565.5	432.8
Other Power Suppliers [Member] | Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		165.8	168.7	138.8
Other [Member] | Regulated Operations [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		101.2	112.3	94.3
Long-term PSA [Member] | ALLETE Clean Energy [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		77.2	75.5	68.3
ALLETE Clean Energy Other [Member] | ALLETE Clean Energy [Member]
Segment Reporting Information [Line Items]
Other – Non-utility																		7.6	11.4	11.3
Long-term Contract [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		89.2	84.4	86.0
Sale of Renewable Development Projects | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		73.9	0.0	0.0
Corporate & Other - Other [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax																		30.0	20.0	16.2
Sale of Wind Energy Facility [Member] | ALLETE Clean Energy [Member]
Segment Reporting Information [Line Items]
Sale of Wind Energy Facility																		$ 33.5	$ 0.0	$ 0.0

[1] See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

[2] Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.    

[3] Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. 

[4] 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.)

[5] Net Income in 2022 includes a $8.3 million after-tax expense as a result of purchase price accounting related to projects under development at the time of acquisition and $2.7 million after-tax of transaction costs related to the acquisition of New Energy.

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Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	[1]	Sep. 30, 2020	[1]	Jun. 30, 2020	[1]	Mar. 31, 2020	[1]	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Selected Quarterly Financial Information [Abstract]
Operating Revenue	$ 425.8	$ 388.3	$ 373.1	$ 383.5	$ 399.0	$ 345.4	$ 335.6	$ 339.2	$ 320.4		$ 293.9		$ 243.2		$ 311.6		$ 1,570.7	$ 1,419.2	$ 1,169.1
Operating Income	33.7	33.4	13.7	53.4	50.0	31.1	28.2	42.0	23.7		41.6		12.7		60.2		134.2	151.3	138.2
Net Income Attributable to ALLETE	$ 51.7	$ 33.7	$ 37.6	$ 66.3	$ 61.9	$ 27.6	$ 27.9	$ 51.8	$ 38.3		$ 40.7		$ 20.1		$ 66.3		$ 189.3	$ 169.2	$ 165.4
Basic Earnings Per Share of Common Stock	$ 0.90	$ 0.59	$ 0.67	$ 1.24	$ 1.18	$ 0.53	$ 0.53	$ 0.99	$ 0.74		$ 0.78		$ 0.39		$ 1.28		$ 3.38	$ 3.23	$ 3.18
Diluted Earnings Per Share of Common Stock	$ 0.90	$ 0.59	$ 0.67	$ 1.24	$ 1.18	$ 0.53	$ 0.53	$ 0.99	$ 0.73		$ 0.78		$ 0.39		$ 1.28		$ 3.38	$ 3.23	$ 3.18

[1] See Immaterial Revision to Prior Period in Note 1. Operations and Significant Accounting Policies.

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Schedule II (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Trade Accounts Receivable [Member]
Valuation and Qualifying Accounts and Reserves [Roll Forward]
Balance at Beginning of Period		$ 1.8	$ 2.5	$ 0.9
Additions, Charged to Income		1.9	1.2	2.7
Additions, Other Charges		0.0	0.0	0.0
Deductions from Reserves	[1]	2.1	1.9	1.1
Balance at End of Period		1.6	1.8	2.5
Finance Receivables – Long-Term [Member]
Valuation and Qualifying Accounts and Reserves [Roll Forward]
Balance at Beginning of Period		0.0	0.0	0.0
Additions, Charged to Income		0.0	0.0	0.0
Additions, Other Charges		0.0	0.0	0.0
Deductions from Reserves	[1]	0.0	0.0	0.0
Balance at End of Period		0.0	0.0	0.0
Deferred Tax Assets [Member]
Valuation and Qualifying Accounts and Reserves [Roll Forward]
Balance at Beginning of Period		69.0	69.9	70.0
Additions, Charged to Income		(8.8)	(0.9)	(0.1)
Additions, Other Charges		0.0	0.0	0.0
Deductions from Reserves	[1]	0.0	0.0	0.0
Balance at End of Period		$ 60.2	$ 69.0	$ 69.9

[1] Includes uncollectible accounts written-off.