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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

(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)

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:

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 ☐

        Large Accelerated Filer    ☒             Accelerated Filer    ☐

         Non-Accelerated Filer    ☐         Smaller Reporting Company    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes ☐     No ☒

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

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

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

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

•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;

•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.

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.

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.)

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.

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.

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.)

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 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 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.

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.

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.)

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.

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.

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.

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.)

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.

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.

															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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.)

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.

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.

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.

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.

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

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.

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.

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.

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.

•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.

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

			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

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.

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.

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.

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)

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.)

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

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.)

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.

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.

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.

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.

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.

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 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.

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.

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.

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.

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.)

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.

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.

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.

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.

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.

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.

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.)

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.

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.

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.

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.

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.

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.

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.)