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, 2024

 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.

 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).

 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 28, 2024, was $ 3,591,830,978.

 As of February 1, 2025, there were 57,901,153 shares of ALLETE Common Stock, without par value, outstanding.

 Documents Incorporated By Reference
 Portions of the Proxy Statement for the 2025 Annual Meeting of Shareholders are incorporated by reference in Part III.

 Definitions

 Forward-Looking Statements

 Item 1. Business

 Electric Sales / Customers

 Seasonality

 Power Supply

 Transmission and Distribution

 Investment in ATC

 Properties

 Regulatory Matters

 Regional Organizations

 Minnesota Legislation

 Competition

 Franchises

 New Energy

 Investment in Nobles 2

 South Shore Energy

 BNI Energy

 ALLETE Properties

 Non-Rate Base Generation and Miscellaneous

 Environmental Matters

 Human Capital Management

 Availability of Information

 Information about our Executive Officers

 Item 1A. Risk Factors

 Item 1B. Unresolved Staff Comments

 Item 1C. Cybersecurity

 Item 2. Properties

 Item 3. Legal Proceedings

 Item 4. Mine Safety Disclosures

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

 Item 6. [Reserved]

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

 Overview

 2024 Compared to 2023

 Critical Accounting Policies

 Outlook

 Liquidity and Capital Resources

 Capital Requirements

 Environmental and Other Matters

 Market Risk

 Recently Adopted Accounting Standards

 Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 Item 8. Financial Statements and Supplementary Data

 Index (Continued)
 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item 9A. Controls and Procedures

 Item 9B. Other Information

 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Item 10. Directors, Executive Officers and Corporate Governance

 Item 11. Executive Compensation

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

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

 Item 14. Principal Accountant Fees and Services

 Item 15. Exhibits and Financial Statement Schedules

 Item 16. Form 10-K Summary

 Signatures

 Report of Independent Registered Public Accounting Firm

 Consolidated Financial Statements - Audited

 Consolidated Balance Sheet

 Consolidated Statement of Income

 Consolidated Statement of Comprehensive Income

 Consolidated Statement of Cash Flows

 Consolidated Statement of Equity

 Notes to Consolidated Financial Statements

 Note 1. Operations and Significant Accounting Policies

 Note 2. Property, Plant and Equipment

 Note 3. Jointly-Owned Facilities and Assets

 Note 4. Regulatory Matters

 Note 5. Acquisitions

 Note 6. Equity Investments

 Note 7. Fair Value

 Note 8. Short-Term and Long-Term Debt

 Note 9. Commitments, Guarantees and Contingencies

 Note 10. Common Stock and Earnings Per Share

 Note 11. Income Tax Expense

 Note 12. Pension and Other Postretirement Benefit Plans

 Note 13. Employee Stock and Incentive Plans

 Note 14. Business Segments

 Note 15. Agreement and Plan of Merger

 Note 16. Quarterly Financial Data (Unaudited)

 Schedule II

 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, 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

 Alloy Merger Sub
 Alloy Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of Alloy Parent.

 Alloy Parent
 Alloy Parent LLC, a Delaware limited liability company which, upon closing, will be jointly owned by a wholly owned subsidiary of Canada Pension Plan Investment Board and affiliates of investment vehicles affiliated with one or more funds, accounts, or other entities managed or advised by Global Infrastructure Management, LLC

 ARO
 Asset Retirement Obligation

 ASU
 Accounting Standards Update

 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

 C&I
 Commercial and Industrial

 Caddo
 ALLETE Clean Energy's Caddo Wind Energy Facility

 Camp Ripley
 Camp Ripley Solar Array

 CCR
 Coal Combustion Residuals from Electric Utilities

 Cenovus Energy
 Cenovus Energy Inc.

 Cliffs
 Cleveland-Cliffs Inc.

 Company
 ALLETE, Inc. and its subsidiaries

 COVID-19
 2019 novel coronavirus

 CSAPR
 Cross-State Air Pollution Rule

 CTO
 Chief Technology Officer

 DC
 Direct Current

 D.C. Circuit
 District of Columbia Circuit Court of Appeals

 Diamond Spring
 ALLETE Clean Energy's Diamond Spring Wind Energy Facility

 DOC
 U.S. Department of Commerce

 ECO
 Energy Conservation and Optimization

 EPA
 United States Environmental Protection Agency

 ELG
 Effluent Limitation Guidelines

 ESOP
 Employee Stock Ownership Plan

 Executive Officers of ALLETE
 Chair, President and Chief Executive Officer; Vice President and President of ALLETE Clean Energy; Senior Vice President and Chief Financial Officer; Vice President, Chief Legal Officer and Corporate Secretary; Vice President and Corporate Treasurer; and Vice President and Chief Operating Officer of Minnesota Power

 FASB
 Financial Accounting Standards Board

 Abbreviation or Acronym
 Term

 FERC
 Federal Energy Regulatory Commission

 FGD
 Flue Gas Desulphurization

 FIP
 Federal Implementation Plan

 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.

 HSR Act
 Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations promulgated thereunder

 HLBV
 Hypothetical Liquidation at Book Value

 Husky Energy
 Husky Energy Inc.

 HVDC
 High-Voltage Direct-Current

 IBEW
 International Brotherhood of Electrical Workers

 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

 LLC
 Limited Liability Company

 MACT
 Maximum Achievable Control Technology

 MATS
 Mercury and Air Toxics Standards

 Manitoba Hydro
 Manitoba Hydro-Electric Board

 MBtu
 Million British thermal units

 Merger
 Pursuant to the Merger Agreement, on the terms and subject to the conditions set forth therein, Alloy Merger Sub will merge with and into ALLETE (the "Merger"), with ALLETE continuing as the surviving corporation in the Merger and becoming a subsidiary of Alloy Parent

 Merger Agreement
 Agreement and Plan of Merger, dated as of May 5, 2024, by and among ALLETE, Alloy Parent, and Alloy Merger Sub

 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

 MRO
 Midwest Reliability Organization

 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

 Nippon Steel
 Nippon Steel Corporation

 Abbreviation or Acronym
 Term

 NIST
 National Institute of Standards and Technology

 Nobles 2
 Nobles 2 Power Partners, LLC

 NOL
 Net Operating Loss

 NO2

 Nitrogen Dioxide

 NOX

 Nitrogen Oxides

 Northern States Power
 Northern States Power Company, a subsidiary of Xcel Energy Inc.

 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

 Palm Coast Park District
 Palm Coast Park Community Development District in Florida

 PPA / PSA
 Power Purchase Agreement / Power Sales Agreement

 PPACA
 Patient Protection and Affordable Care Act of 2010

 PSCW
 Public Service Commission of Wisconsin

 PV
 Photovoltaic

 RFP
 Request for Proposals

 RSOP
 Retirement Savings and Stock Ownership Plan

 RTO
 Regional Transmission Organization

 SEC
 Securities and Exchange Commission

 Silver Bay Power
 Silver Bay Power Company, a wholly-owned subsidiary of Cliffs

 SIP
 State Implementation Plan

 SO2

 Sulfur Dioxide

 SOC
 System and Organizational Controls

 Sofidel
 The Sofidel Group

 South Shore Energy
 South Shore Energy, LLC

 Square Butte
 Square Butte Electric Cooperative, a North Dakota cooperative corporation

 Standard & Poor's / S&P
 S&P Global Ratings

 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

 VEBA
 Voluntary Employee Benefit Association

 VIE
 Variable Interest Entities

 WTG
 Wind Turbine Generator

 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, the direct and indirect effects of new or changes in existing tariffs, or changes in tax rates or policies;
 • changes in rates of inflation or availability of key materials and suppliers;
 • the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;
 • weather conditions, natural disasters and pandemic diseases;
 • 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;
 • the success of efforts to realize value from, invest in, and develop new opportunities;
 • the risk that Alloy Parent or ALLETE may be unable to obtain governmental and regulatory approvals required for the Merger, or that required governmental and regulatory approvals or agreements with other parties interested therein may delay the Merger, may subject the Merger to or impose adverse conditions or costs, or may cause the parties to abandon the Merger;
 • the timing and costs incurred to consummate the Merger;
 • the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement or could otherwise cause the failure of the Merger to be consummated on the timeline anticipated; and
 Forward Looking Statements (Continued)

 • the announcement and pendency of the Merger, during which ALLETE is subject to certain operating restrictions, could have an adverse effect on ALLETE's businesses, results of operations, financial condition or cash flows.

 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.

 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 in 2024 delivered 55 percent renewable energy to those customers. Minnesota Power is making significant progress toward 100 percent carbon-free energy supply—a vision grounded in a steadfast commitment to climate, customers and community through its EnergyForward strategy. ALLETE Clean Energy, our second-largest business, is positioned at the heart of society's clean-energy transformation and owns, operates and has developed for others more than 1,600 megawatts of wind energy generation across eight states—helping some of the largest companies in the country reduce their carbon footprint. Our newest business, New Energy, is a leading developer of community, commercial and industrial, and small utility-scale renewable energy projects that has completed more than 575 MW in its history.

 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 company-owned 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 a law 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. Ongoing progress towards compliance with Minnesota's carbon-free standard is evaluated in IRP proceedings at the MPUC. Minnesota Power's next IRP will be filed in March 2025 and address progress towards compliance with the 2040 law. Minnesota Power is also working with various stakeholders and participating in the regulatory process to implement this law. (See Regulated Operations – Minnesota Legislation.)

 On May 5, 2024, ALLETE entered into the Merger Agreement. The Merger Agreement provides that, on and subject to the conditions set forth therein, Alloy Merger Sub will merge with and into ALLETE, with ALLETE continuing as the surviving corporation in the Merger and becoming a subsidiary of Alloy Parent. (See Note 15. Agreement and Plan of Merger.)

 For more information regarding the terms of the Merger, including a copy of the Merger Agreement, see ALLETE's Current Report on Form 8-K filed with the SEC on May 5, 2024, and ALLETE's definitive proxy statement relating to the special meeting of shareholders filed with the SEC on July 10, 2024.

 ALLETE is 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, 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.)

 Overview (Continued)

 ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns, operates, or has developed more than 1,600 megawatts of wind energy generation in five major energy markets and eight states across the U.S. 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.

 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, 2024, 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.

 2024
 2023
 2022

 Consolidated Operating Revenue – Millions (a)

 $1,529.8
 $1,879.8
 $1,570.7

 Percentage of Consolidated Operating Revenue

 %
 %
 %

 ALLETE Clean Energy (a)

 %
 %
 %

 %
 %
 %

 %
 %
 %

 (a) Consolidated operating revenue for 2023 includes the sales of ALLETE Clean Energy's Northern Wind and Red Barn projects.

 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.

 REGULATED OPERATIONS

 Electric Sales / Customers

 Regulated Utility Kilowatt-hours Sold

 2024
 %
 2023
 %
 2022
 %

 Retail and Municipal

 Residential
 1,069
 1,089
 1,148

 Commercial
 1,322
 1,347
 1,359

 Industrial
 7,022
 7,044
 6,745

 Municipal

 Total Retail and Municipal
 9,882
 9,946
 9,792

 Other Power Suppliers
 2,680
 2,819
 3,149

 Total Regulated Utility Kilowatt-hours Sold
 12,562
 12,765
 12,941

 Industrial Customers. In 2024, industrial customers represented 56 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. Cliffs idled all production at its Northshore mine in 2022 and resumed partial pellet plant production in April 2023. (See Outlook – Regulated Operations – Industrial Customers – Taconite.)

 Industrial Customer Kilowatt-hours Sold

 2024
 %
 2023
 %
 2022
 %

 4,897
 4,935
 4,713

 Paper, Pulp and Secondary Wood Products

 Pipelines and Other Industrial
 1,411
 1,440
 1,297

 Total Industrial Customer Kilowatt-hours Sold
 7,022
 7,044
 6,745

 Six taconite facilities served by Minnesota Power made up approximately 80 percent of 2023 iron ore pellet production in the U.S. according to data from the Minnesota Department of Revenue 2024 Mining Tax Guide. These taconite facilities are owned by Cliffs and USS Corporation. (See Large Power Customer Contracts.) Sales to taconite customers represented 4,897 million kWh, or 70 percent, of total industrial customer kWh sales in 2024. 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 steelmaking 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, approximately 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 76 percent of capacity in 2024 (75 percent in 2023 and 78 percent in 2022). 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 2025 will increase by approximately 2 percent compared to 2024.

 Industrial Customers (Continued)

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

 Minnesota Power Taconite Customer Production

 Year
 Tons (Millions)

 2024*

 2023

 2022

 2021

 2020

 2019

 2018

 2017

 2016

 2015

 Source: Minnesota Department of Revenue 2024 Mining Tax Guide for years 2015 - 2023.

 * 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 $0.07, 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 714 million kWh, or 10 percent of total industrial customer kWh sales in 2024. 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 2024 compared to 2023. Sofidel completed the acquisition of the Duluth Mill from ST Paper in the first quarter of 2024. In the third quarter of 2024, Sofidel announced plans to invest between $200 million and $250 million to add a conversion facility and automated warehouse to the tissue plant. (See Outlook – Regulated Operations – Industrial Customers – Paper, Pulp and Secondary Wood Products – Sofidel.)

 Large Power Customer Contracts. Minnesota Power had eight Large Power Customer contracts as of December 31, 2024, each serving requirements of 10 MW or more of customer load. Certain facilities with common ownership are served under combined contracts. The customers as of December 31, 2024, consisted of six taconite facilities owned by Cliffs and USS Corporation as well as four paper and pulp mills. Minnesota Power also serves Northshore Mining through a PSA with its affiliate Silver Bay Power, in addition to the load served through its Large Power Customer contract with United Taconite and Northshore Mining. (See Silver Bay Power PSA.)

 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, 2024
 Customer
 Industry
 Location
 Ownership
 Earliest
Termination Date

 Cliffs – Minorca Mine (a)

 Virginia, MN
 Cliffs

 Hibbing Taconite (a)(d)

 Hibbing, MN
 85.3% Cliffs
14.7% USS Corporation

 United Taconite and Northshore Mining (a)

 Eveleth, MN and Babbitt, MN
 Cliffs

 USS Corporation
 (USS – Minnesota Ore) (b)(d)

 Mtn. Iron, MN and Keewatin, MN
 USS Corporation
 (e)

 Boise, Inc. (a)

 Paper
 International Falls, MN
 Packaging Corporation of America

 UPM Blandin
 Paper
 Grand Rapids, MN
 UPM-Kymmene Corporation
 December 31, 2029

 Sappi Cloquet LLC (a)

 Paper and Pulp
 Cloquet, MN
 Sappi Limited

 Sofidel (c)

 Paper
 Duluth, MN
 Sofidel
 February 28, 2029

 (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, 2028.
 (b)USS Corporation owns both the Minntac Plant in Mountain Iron, MN, and the Keewatin Taconite Plant in Keewatin, MN.
 (c)Sofidel completed the acquisition of the Duluth Mill from ST Paper in the first quarter of 2024. (See Outlook – Regulated Operations – Industrial Customers – Paper, Pulp and Secondary Wood Products.)
 (d)In December 2023, USS Corporation announced it entered into a definitive agreement in which Nippon Steel will acquire all of USS Corporation's stock. (See Outlook – Regulated Operations – Industrial Customers – Taconite.)
 (e)On January 27, 2025, USS Corporation exercised its rights under its electric service agreement with Minnesota Power to provide a four-year notice of termination. Minnesota Power and USS Corporation are working together to meet USS Corporation's evolving energy needs. Absent any other action by the parties, the termination of the current electric service agreement would be effective January 27, 2029, and USS Corporation would become a non-contract large power customer of Minnesota Power.

 Silver Bay Power PSA. Minnesota Power has a PSA with Silver Bay Power through 2031 to supply its full energy requirements. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power.

 Residential and Commercial Customers. In 2024, residential and commercial customers represented 19 percent of total regulated utility kWh sales.

 Municipal Customers. In 2024, 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 3-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 41 percent to Minnkota Power in 2024 (37 percent in 2023 and 32 percent in 2022). Minnkota Power's net entitlement increases to approximately 46 percent in 2025 and 50 percent in 2026. (See Power Supply – Long-Term Purchased Power.)

 Hibbing Public Utilities. Minnesota Power has a long-term power contract with Hibbing Public Utilities for the period of June 1, 2022, through May 31, 2027.

 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. In 2024, 55 percent of Minnesota Power's power supply for its retail and municipal customers in Minnesota has been 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.) Renewable energy percentages may vary year to year based on weather, system demand and transmission constraints.

 The following table reflects Minnesota Power's generating capabilities as of December 31, 2024, and total electrical supply for 2024. Minnesota Power had an annual net peak load of 1,532 MW on January 19, 2024.

 Power Supply (Continued)

 Year Ended

 Unit
 Year
 Net
 December 31, 2024

 Regulated Utility Power Supply
 No.
 Installed
 Capability
 Generation and Purchases

 MW
 MWh
 %

 Coal-Fired

 Boswell Energy Center (a)

 1973

 in Cohasset, MN
 1980
 (b)

 3,794,254
 29.2

 Total Coal-Fired
 3,794,254
 29.2

 Biomass Co-Fired / Natural Gas

 Hibbard Renewable Energy Center in Duluth, MN
 3 & 4
 1949, 1951
 66,884
 0.5

 Laskin Energy Center in Hoyt Lakes, MN
 1 & 2
 1953
 172,011
 1.3

 Total Biomass Co-Fired / Natural Gas
 238,895
 1.8

 Hydro (c)

 Group consisting of ten stations in MN
 504,384
 3.9

 Wind (d)

 Taconite Ridge Energy Center in Mtn. Iron, MN
 2008
 47,389
 0.4

 Bison Wind Energy Center in Oliver and Morton Counties, ND
 2010-2014
 1,232,079
 9.5

 Total Wind
 1,279,468
 9.9

 Solar (e)

 Group consisting of two solar arrays in MN
 15,104
 0.1

 Total Generation
 1,630
 5,832,105
 44.9

 Long-Term Purchased Power

 Lignite Coal - Square Butte near Center, ND (f)

 1,508,295
 11.6

 Wind - Oliver Wind I and II in Oliver County, ND
 357,727
 2.8

 Wind - Nobles 2 in Nobles County, MN (g)

 978,793
 7.5

 Hydro - Manitoba Hydro in Manitoba, Canada
 1,463,184
 11.3

 Solar - Purchases from five solar arrays in MN
 40,791
 0.3

 Total Long-Term Purchased Power
 4,348,790
 33.5

 Other Purchased Power (h)

 2,798,454
 21.6

 Total Purchased Power

 7,147,244
 55.1

 Total Regulated Utility Power Supply

 12,979,349
 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)Hydro consists of 10 stations with 34 generating units.
 (d)Taconite Ridge consists of 10 WTGs and Bison consists of 165 WTGs.
 (e)Solar includes the 10 MW Camp Ripley Solar Array near Little Falls, MN, and a 40 kW community solar garden in Duluth, MN.
 (f)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.)
 (g)See Item 1. Business – Corporate and Other – Investment in Nobles 2.
 (h)Includes short-term market purchases in the MISO market and from Other Power Suppliers.

 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 2024 for electric generation at Minnesota Power's coal-fired generating stations was 2.3 million tons (2.7 million tons in 2023; 2.7 million tons in 2022). As of December 31, 2024, Minnesota Power had coal inventories of 0.6 million tons (0.7 million tons as of December 31, 2023). Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2025. In 2025, 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 2027. 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

 2024
 2023
 2022

 Average Price per Ton
 $40.20
 $41.23
 $39.98

 Average Price per MBtu
 $2.20
 $2.30
 $2.25

 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 2024 was approximately $2.25 per MBtu ($2.36 per MBtu in 2023; $2.05 per MBtu in 2022). (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.

 Wind Energy. 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.) 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.

 Solar Energy. Minnesota Power purchases solar energy from approximately 20 MW of solar energy facilities located in Minnesota that are owned by an ALLETE subsidiary, and a one MW community solar garden in northeastern Minnesota, which is owned and operated by a third party.

 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), 115 kV (1,387 miles) and less than 115 kV (6,685 miles). We own and operate 154 substations with a total capacity of 10,647 megavolt-amperes. Some of our transmission and distribution lines interconnect with other utilities, and we own some of our transmission lines jointly with other utilities. (See Note 3. Jointly-Owned Facilities and Assets and Outlook – Regulated Operations – Transmission.)

 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.

 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, 2024, our equity investment in ATC was $194.4 million ($179.7 million as of December 31, 2023). (See Note 6. Equity Investments.)

 ATC's authorized return on equity was 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. On October 17, 2024, FERC ordered a return on equity of 9.98 percent, or 10.48 percent including an incentive adder for participation in a RTO, effective September 28, 2016.

 In addition, the FERC issued a Notice of Proposed Rulemaking in April 2021 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 2024 through 2033, identifies a need for between $8.9 billion and $10.9 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 and distribution 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 retail base rates through 2022 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. Interim rates were implemented in Minnesota Power's 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power's 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See 2022 Minnesota General Rate Case.) Minnesota Power expects to implement updated rates based on the 2024 MPUC retail rate order in the first quarter of 2025. This order allows for a return on equity of 9.78 percent and an equity ratio of 53.00 percent. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission and renewable investments.

 2024 Minnesota General Rate Case. On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $64 million, net of rider revenue, beginning January 1, 2024, subject to refund.

 On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power's refund calculation.

 2022 Minnesota General Rate Case. In an order dated February 28, 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. In March 2023, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration and clarification of certain decisions in the MPUC's order. The MPUC denied the requests for reconsideration in an order dated May 15, 2023.

 In an order dated September 29, 2023, the MPUC approved Minnesota Power's final rates, which were implemented beginning on October 1, 2023. The MPUC order also approved Minnesota Power's interim rate refund plan. Interim rates were collected through the third quarter of 2023 with reserves recorded as necessary. Minnesota Power recorded a reserve for an interim rate refund of approximately $39 million pre-tax as of September 30, 2023 (approximately $18 million as of December 31, 2022), which was refunded to customers during the fourth quarter of 2023.

 Minnesota Power appealed with the Minnesota Court of Appeals (Court) specific aspects of the MPUC's February 2023 and May 2023 rate case orders for the ratemaking treatment of Taconite Harbor and Minnesota Power's prepaid pension asset. On September 9, 2024, the Court affirmed the MPUC's Taconite Harbor treatment, but reversed and remanded the treatment of Minnesota Power's prepaid pension asset back to the MPUC. The Court directed the MPUC to determine the amount of Minnesota Power's prepaid pension asset to be included in rate base. The MPUC has not yet determined the next procedural steps in implementing the Court's decision.

 Regulatory Matters (Continued)

 Minnesota Power Land Sales. In August 2020, Minnesota Power filed a petition with the MPUC for approval to sell land that surrounds several reservoirs on its hydroelectric system and is no longer required to maintain its operations. The land had 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 a November 2021 order, the MPUC authorized the land sales and directed the net proceeds to be refunded to ratepayers subject to certain conditions and required compliance filings. As of December 31, 2024, we have a regulatory liability recorded of $59.7 million related to these sales.

 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 in March 2025.

 Minnesota Power is making significant progress toward 100 percent carbon-free energy supply, continuing its commitment to climate, customers and communities through its EnergyForward strategy. This vision builds on Minnesota Power's achievement, in 2020, of 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 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P's 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See 2022 Wisconsin General Rate Case.) The resolution of SWL&P's 2024 general rate case further changed the allowed return on equity to 9.80 percent and continued to maintain an equity ratio of 55.00 percent beginning January 1, 2025. (See 2024 Wisconsin General Rate Case.)

 2024 Wisconsin General Rate Case. On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generate an estimated $7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025.

 2022 Wisconsin General Rate Case. In an order dated December 20, 2022, the PSCW approved an annual increase of $3.3 million reflecting a return on equity of 10.00 percent and a 55.00 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 recordkeeping 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 noncompliance.

 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. Ongoing progress towards compliance with Minnesota's Carbon Free Standard is evaluated in the IRP proceedings at the MPUC. Minnesota Power's next IRP will be filed in March 2025 and discuss progress towards compliance with the 2040 law. Minnesota Power is also working with various stakeholders and participating in the regulatory process to implement this legislation.

 In 2024, 55 percent of Minnesota Power's power supply for its retail and municipal customers in Minnesota has been provided by renewable energy sources. Minnesota Power's plans include expanding its renewable energy supply to 70 percent renewable energy by 2030. Minnesota Power has also set a target to achieve an 80 percent reduction in carbon emissions by 2035 compared to 2005 levels. (See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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

 Competition

 Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users of 2 MW and above that are located outside of a municipality are allowed to choose a supplier upon MPUC approval. Minnesota Power served eight Large Power Customers under contracts of at least 10 MW in 2024, 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 2024, 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 is effective through 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 certain cities within its service territory. 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 one 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, operates, or has developed more than 1,600 megawatts of wind energy generation in five major energy markets and eight states across the U.S. 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. (See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Outlook – ALLETE Clean Energy.)

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

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

 ALLETE CLEAN ENERGY (Continued)

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

 Region
 Wind Energy Facility
 Capacity MW
 MW
 PSA Expiration

 East
 Armenia Mountain

 PSA 1
 50%
 2031

 PSA 2
 50%
 2031

 Midwest
 Lake Benton
 100%
 2028

 Storm Lake I
 100%
 2027

 Storm Lake II

 Merchant
 90%
 n/a

 PSA
 10%
 2032

 Other
 100%
 2028

 South
 Caddo

 Merchant
 27%
 n/a

 PSA 1
 66%
 2034

 PSA 2
 7%
 2034

 Diamond Spring

 PSA 1
 58%
 2035

 PSA 2
 25%
 2032

 PSA 3
 17%
 2035

 West
 Condon
 100%
 2028

 Glen Ullin
 100%
 2039

 South Peak
 100%
 2035

 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. 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

 In April 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 575 MW in its history, totaling more than $1.4 billion of capital. New Energy currently has a robust project pipeline with greater than 2,000 MW of renewable projects in development across over 20 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, owning and operating 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. As of December 31, 2024, our equity investment in Nobles 2 was $145.7 million ($151.5 million at December 31, 2023). (See Note 6. Equity Investments.)

 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 upon the completion of the facility 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 will be responsible for approximately 20 percent. South Shore Energy's portion of NTEC project costs incurred through December 31, 2024, is approximately $10 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, 2024, 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 200 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, 2024, outstanding finance receivables were $3.5 million, net of reserves, with maturities through 2029. 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, 2024, 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, and approximately 20 MW of solar energy facilities located in Sylvan, Hoyt Lakes, and Duluth, Minnesota, which sell energy generated to Minnesota Power.

 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 recruit 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, 2024, ALLETE had 1,616 employees, of which 1,564 were full-time. We also respect employees' freedom of association and their right to collectively organize. As of December 31, 2024, Minnesota Power and SWL&P have an aggregate of 490 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, 2026, for Minnesota Power and January 31, 2027, for SWL&P. BNI Energy has 129 employees that are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2026.

 ALLETE's Human Rights Policy 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 Convention.

 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 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 to improve safety performance. Leaders have regular safety conversations with employees, where hazard identification and controls are discussed to ensure we have defenses in depth and the capability to work safely. To monitor progress, the Company uses both leading and lagging indicators to analyze safety performance, injury trends, program participation and other data, such as data from our Company-wide safety perception survey to make informed decisions on safety practices aligned with direct input from our valued employees.

 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 pathways 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, supervisory and leadership development programs, and mentoring. 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 training—including apprenticeships and scholarships aimed at bridging opportunity gaps—as we recognize the importance of a strong talent pathway. Our internship program and our partnerships and participation in outreach programs with local schools and colleges attract students to careers in the energy industry.

 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 among 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.

 Living Our People Value. We care for people – our employees, our customers, the communities in which we serve, and our investors. We demonstrate this care by respecting and embracing differences and creating an environment where everyone feels included and can thrive. We believe that a workforce comprised of diverse backgrounds and experiences, where everyone is welcome and treated equitably, leads to stronger outcomes for all stakeholders.

 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 strive to ensure our People value is demonstrated in the areas of workforce, supply chain, communications, customer relations, and community citizenship at ALLETE. ALLETE continues to take tangible steps toward advancing efforts by continuing to raise awareness and furthering intentional external relationships and partnerships.

 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.

 INFORMATION ABOUT OUR EXECUTIVE OFFICERS

 As of February 13, 2025, these are the executive officers of ALLETE:

 Executive Officers
 Initial Effective Date

 Bethany M. Owen, Age 59

 Chair, President and Chief Executive Officer
 May 11, 2021

 President and Chief Executive Officer
 February 3, 2020

 Nicole R. Johnson, Age 50

 Vice President and President of ALLETE Clean Energy
 August 22, 2022

 Vice President and Chief Administrative Officer
 June 28, 2019

 Steven W. Morris, Age 63 (a)

 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

 Julie L. Padilla, Age 49

 Vice President, Chief Legal Officer and Corporate Secretary
 June 1, 2024

 Jeffrey J. Scissons, Age 48

 Vice President and Corporate Treasurer
 September 19, 2024

 Joshua J. Skelton, Age 45

 Vice President and Chief Operating Officer of Minnesota Power
 August 22, 2022

 (a) On January 24, 2025, ALLETE announced the planned retirement of Steven W. Morris. As part of an orderly transition, Mr. Morris will remain at the Company through his retirement date of July 18, 2025.

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

 • Mr. Skelton was Chief Operating Officer of Minnesota Power from November 2020 to August 2022; and Vice President Generation Operations and ALLETE Safety from May 2019 to November 2020.
 • Mr. Scissons was ALLETE Corporate Development and ALLETE Clean Energy Strategy Officer from September 2023 to September 2024; ALLETE Clean Energy Chief Financial and Strategy Officer from January 2022 to September 2023; Director Corporate Development from January 2021 to January 2022; and Assistant Treasurer from January 2017 to January 2021.

 During the past five years, Ms. Padilla held positions as Chief Regulatory Officer at Twin Metals Minnesota from April 2019 to July 2022 and an attorney at Fryberger Law Firm from November 2022 to April 2024.

 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 13, 2025.

 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 31 percent of our 2024 consolidated operating revenue (24 percent in 2023 and 29 percent in 2022) and 38 percent of Regulated Operations operating revenue (36 percent in 2023 and 36 percent in 2022). Minnesota Power's taconite customers, which are currently owned by only two entities at the end of 2024, accounted for approximately 27 percent of consolidated operating revenue and 33 percent of Regulated Operations operating revenue in 2024. This concentrated ownership presents customer concentration risk for the Company, and could lead to further capacity consolidation for both steel blast furnaces and related Minnesota iron ore production. These customers are also 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 2024 consolidated operating revenue (2 percent in 2023 and in 2022) and 2 percent of Regulated Operations revenue in 2024 (3 percent in 2023 and 2 percent in 2022). 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 or operate their facilities, 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.

 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. In addition, our ability to manage changing regulations could be impacted by our rights and obligations under joint ownership agreements.

 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.

 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. On August 12, 2024, Minnesota Power received a Notice of Violation (NOV) from the MPCA, related to the spill at Boswell from a pipeline carrying ash wastewater from an inactive onsite storage pond to Blackwater Creek, which the Company reported on July 16, 2024. Minnesota Power continues to work with state and federal agencies to evaluate and mitigate the impacts from this event. We are unable to predict the mitigation or other costs related to the ash wastewater spill at this time; however, the costs could be material. (See Note 9. Commitments, Guarantees and Contingencies.)

 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 2024, our operating coal-fired generating facilities consisted of the 352 MW Boswell Unit 3 and the 468 MW Boswell Unit 4. (See Item 7. Management Discussion and Analysis of Financial Condition and Results of Operation – 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 noncompliance.

 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. Our ability to manage and operate certain facilities could also be impacted by our rights and obligations under the joint ownership agreements. 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.

 Regulated Operations Risks (Continued)

 Our ability to successfully and timely complete capital repairs or improvements to existing regulated facilities or in the development of new electric generation and transmission 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, if we are unable to obtain the necessary permits, land rights and regulatory approvals, 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.

 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, cybersecurity attacks or other catastrophic events; and
 • federal, state, local and foreign energy, environmental, or other regulation and legislation, including the direct and indirect effects of new or changes in tariffs.

 Volatility in market prices for our fuel and purchased 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.)

 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 and obtain all required permits and approvals. 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 and operations of recently acquired entities are subject to uncertainties. If we are unable to successfully integrate and manage 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.

 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.

 ALLETE Clean Energy / Corporate and Other Risks (Continued)

 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 or due to inadequate transmission capacity; 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 commercial 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, or lead to potential impairment of property, plant and equipment if these conditions persist for an extended period of time.

 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 2027 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, 2024, 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.

 ALLETE Clean Energy / Corporate and Other Risks (Continued)

 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 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.

 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 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.

 Entity-wide Risks (Continued)

 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. Management's Discussion and Analysis of Financial Condition and Results of Operations – 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.

 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.

 The U.S. government currently imposes anti-dumping 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). On August 18, 2023, the U.S. DOC issued a final affirmative determination that imports of certain PV cells and modules assembled and completed in Cambodia, Malaysia, Thailand, and Vietnam are circumventing anti-dumping and countervailing duties. Duties were not collected on imports before June 2024 as a result of a temporary duty suspension ordered by the U.S. President. Our operating results could be adversely impacted if this U.S. DOC circumvention determination results in duties assessed on future purchases made by our businesses after the current moratorium ends, or if additional anti-dumping and countervailing duties are imposed by the U.S. government on products purchased by our businesses.

 Entity-wide Risks (Continued)

 Our results of operations could be adversely affected by changes in governmental policy related to taxes, tariffs and duties, as well as grants and other incentives.

 Our business, investments and customers could be adversely affected by the direct and indirect effects of recently proposed and new tariffs, or changes in existing tariffs, on purchases from suppliers located outside of the U.S. or suppliers with products sourced from outside of the U.S.

 Minnesota Power has PPAs that provide for the purchase of capacity and energy from Manitoba Hydro in Canada and also purchases other energy and capacity through MISO or under bilateral contracts with other power suppliers that may be sourced from outside of the U.S. A portion of SWL&P's natural gas purchases for resale in its regulated service territory is also sourced from Canada. In addition, the Company has various other agreements for the purchase of equipment and other components for use in our operations or capital projects that may be sourced from outside the U.S. We are evaluating the impact of proposed tariffs on our operations, capital projects and purchases from and agreements with suppliers.

 The U.S. Department of Energy (DOE) previously awarded grants on two transmission projects that are currently under various stages of development. (See Outlook – Transmission – North Plains Connector Development Agreement and HVDC Transmission System Project.) These projects could be materially affected by changes in DOE's funding policies.

 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. If we are unable to obtain all required permits and approvals for our development projects, it could negatively impact our ability to execute on our EnergyForward strategy. Adoption of new laws, rules, regulations, principles, public policy positions or practices and their interpretations by federal and state agencies, or changes to or a failure to comply with current laws, rules, regulations, principles, public policy positions 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.

 Entity-wide Risks (Continued)

 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, such as our code of business conduct, by employees, directors of ALLETE, contractors, vendors and others who do business with or on behalf of ALLETE, 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.

 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. 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.

 Entity-wide Risks (Continued)

 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.

 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.

 Our business, financial position, results of operations, and cash flows could be materially affected by adverse results of litigation.

 We are involved in litigation arising in the normal course of business. Unfavorable resolution of legal or administrative proceedings in which we are involved or other future legal or administrative proceedings may have an adverse effect on our business, financial position, results of operations and cash flows.

 Risks Relating to the Merger

 On May 5, 2024, ALLETE entered into the Merger Agreement. (See Note 15. Agreement and Plan of Merger.)

 There is no assurance when or if the Merger will be completed, and there could be an adverse effect on the Company's business, results of operations, financial condition or cash flows if the Merger is not completed or is delayed.

 Consummation of the Merger is subject to various closing conditions, including: (1) approval of the shareholders of ALLETE; (2) receipt of all required regulatory approvals without the imposition of a Burdensome Condition (as defined in the Merger Agreement); (3) absence of any law or order prohibiting the consummation of the Merger; (4) subject to materiality qualifiers, the accuracy of each party's representations and warranties; (5) each party's compliance in all material respects with its obligations and covenants under the Merger Agreement; and (6) the absence of a material adverse effect with respect to the Company. The Merger Agreement also contains certain termination rights for both ALLETE and Alloy Parent, including if the Merger is not consummated by August 5, 2025 (subject to extension for an additional two successive three-month periods if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). While the shareholders of ALLETE voted to approve and adopt the Merger Agreement and approve the transactions contemplated thereby, including the Merger, at a special meeting of the shareholders that was held on August 21, 2024, there can be no assurance that the other conditions to completion of the Merger will be satisfied or waived or that other events will not intervene to delay or result in the failure to close the proposed Merger. The Merger Agreement also provides for certain termination rights for each of ALLETE and Alloy Parent. If the Merger Agreement is terminated, there may be various material, adverse consequences to the Company, including that the Company could be required to pay Alloy Parent a termination fee of $116 million under certain specified circumstances. If the Merger is not completed or delayed, there may be negative reactions from the financial markets, including declines in the price of ALLETE's common stock due to the fact that the current price may reflect a market assumption that the Merger will be completed.

 The announcement and pendency of the Merger, during which the Company is subject to certain operating restrictions, could have an adverse effect on the Company's businesses, results of operations, financial condition or cash flows.

 The announcement and pendency of the Merger could disrupt the Company's businesses, and uncertainty about the effect of the Merger may have an adverse effect on the Company. These uncertainties could affect existing employee relationships, disrupt the business of the Company, and could cause suppliers, vendors, partners, lenders and others that deal with the Company to: (1) defer entering into contracts with the Company; or (2) make other decisions concerning the Company or seek to change or cancel existing business relationships with the Company.

 The Merger Agreement also requires the Company to obtain Parent's consent prior to taking certain specified actions while the Merger is pending. These restrictions may prevent the Company from pursuing otherwise attractive business opportunities or making other changes to its business prior to the completion of the Merger.

 The Company will incur substantial transaction fees and costs in connection with the Merger.

 The Company has incurred transaction costs of $22.6 million after-tax through December 31, 2024, and expects to incur additional material expenses in connection with the Merger and completion of the transactions contemplated by the Merger Agreement. Further, even if the proposed Merger is not completed, the Company will need to pay certain costs relating to the proposed Merger incurred prior to the date the proposed Merger was abandoned, such as legal, accounting, financial advisory, filing and printing fees.

 Risks Relating to the Merger (Continued)

 Pending litigation related to the Merger could result in substantial costs and may delay or prevent the Merger from being completed.

 Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs to us and divert management time and resources. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting consummation of the Merger, then that injunction may delay or prevent the Merger from being completed. A complaint has been filed in the U.S. District Court for the Southern District of New York alleging violation of Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, disclosure deficiency in the Preliminary Proxy, and seeking to enjoin the transaction until certain disclosures are corrected. On September 3, 2024, that complaint was voluntarily dismissed without prejudice. Two additional complaints were filed on August 6, 2024, and August 7, 2024, in New York State Supreme Court, alleging negligent misrepresentation and negligence related to alleged deficiencies in the Preliminary Proxy. Those complaints have not been served on any defendant. The Company believes that the complaints are without merit.

 Item 1B. Unresolved Staff Comments

 None.

 Item 1C. Cybersecurity

 ALLETE employs a multilayer approach to addressing cybersecurity risk based on the NIST framework. It has established a dedicated cybersecurity team that utilizes internal and external assessments, automated monitoring tools, and input from public and private partners to identify potential cyber threats. External third-party security firms are engaged to assist with cybersecurity risk assessments, penetration testing and system security analysis. ALLETE's cybersecurity team works in conjunction with the risk management, legal, finance, accounting, operations, and information technology areas to assess the risk these identified cybersecurity threats present to the organization. To ensure consistency, these cybersecurity risk assessments are incorporated into ALLETE's Enterprise Risk Management process, ALLETE's information technology leadership reviews the company's enterprise risk management-level cybersecurity risks on a quarterly basis, and key cybersecurity risks are incorporated into ALLETE's enterprise risk management framework. Cybersecurity risks are managed and controlled through multiple overlapping layers of cybersecurity defenses that include:

 • expert input from both public and private partnerships;
 • the implementation of a comprehensive cybersecurity policy that encompasses but is not limited to social media, acceptable use (devices, wireless, remote access, internet use), information governance, monitoring, authentication, encryption, vulnerability management, third-party management, and recovery;
 • required annual cybersecurity training for all employees with additional supplemental cybersecurity training required based on role;
 • random employee phish testing and follow-up;
 • procedural and automated cyber controls in conjunction with robust detection, mitigation, and recovery capabilities;
 • the integration of multiple threat intelligence sources into our cybersecurity tools and processes;
 • the retention of external cybersecurity threat response resources;
 • the formation of a multidisciplinary cybersecurity incident response team; and
 • multiple cyber event simulation and tabletop exercises per year to hone the cybersecurity incident response team preparedness.

 Item 1C. Cybersecurity (Continued)

 The ALLETE board of directors provides enterprise-level oversight of risks associated with cybersecurity threats through the Audit Committee, which assists the Board in fulfilling its oversight responsibilities regarding the Company's policies and processes with respect to risk assessment and risk management, including any significant non-financial risk exposures; reviewing and discussing the Company's information security policies and internal controls regarding information security; and reviewing the Company's annual disclosures concerning the role of the Board in the risk oversight of the Company. The Audit Committee performs an annual review of the Company's cybersecurity program and receives quarterly updates on key cybersecurity risks, the cybersecurity risk management plan, and cyber incident event trends.

 ALLETE's Chief Technology Officer (CTO) has primary responsibility for the development and oversight of ALLETE's cybersecurity team and the development and maintenance of the company's related cybersecurity policies and procedures. The CTO has over 25 years' experience working in the information and operational technology field and is a registered professional engineer in the State of Minnesota. The company's cybersecurity team continuously assesses the evolving cyber threat landscape based on their expertise and that of our third-party partners. They then work with all parts of ALLETE to protect against, detect, identify, respond to, and recover from the risks that cybersecurity threats present. The cybersecurity team views and responds to cybersecurity risks in a holistic manner, applying a comprehensive multilayered strategy to prevent, detect, and mitigate them. They have identified ALLETE's critical cyber assets and taken appropriate steps to protect them. External expertise is regularly engaged to assess ALLETE's cybersecurity program and help the cybersecurity team to strengthen the organization's monitoring, alerting, prevention, mitigation, and recovery capabilities. Tabletop simulations, third-party cyber vulnerability assessments, maturity assessments, and partnerships are used to assess and refine all elements of our cybersecurity program.

 In addition to managing our own cybersecurity preparedness, we also consider and evaluate cybersecurity risks associated with the use of third-party service providers. Risk assessments are performed against third-party service providers with a specific focus on any sensitive data that is to be shared with them. The internal business owners of ALLETE's applications are required to document user access reviews regularly. We request a System and Organizational Controls (SOC) 2 report from the vendors of our enterprise cloud applications. If they do not provide us with a SOC 2, we seek additional compensating risk assurance in our contract language with them. Risks associated with the use of third-party service providers are managed as part of our overall cybersecurity risk management framework.

 To continually manage and control the material risks that cybersecurity threats present to the organization, ALLETE invests significantly in the cybersecurity elements outlined above. In addition, the Company has made significant investments to fulfill the operational and financial regulatory requirements laid out by the North American Electric Reliability Corporation Critical Infrastructure Protection Standards and Sarbanes-Oxley Act of 2002.

 ALLETE faces a number of cybersecurity risks in connection with its business. Although we believe such risks have not materially affected us, including our business strategy, results of operations, and financial conditions, we have, from time to time, experienced threats to and breaches of our data systems, including malware, phishing and computer virus attacks. See Item 1A. Risk Factors for additional information regarding our organization's cybersecurity risks, which should be read together with this Item 1C. Cybersecurity.

 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.

 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 $0.73 per share on our common stock is payable on March 1, 2025, to the shareholders of record on February 14, 2025. 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, 2025, there were approximately 17,000 common stock shareholders of record. On May 5, 2024, ALLETE entered into the Merger Agreement. (See Note 15. Agreement and Plan of Merger.)

 We do not have a publicly announced stock repurchase program and we did not repurchase any equity securities during the quarter ended December 31, 2024. Under the Merger Agreement, the Company cannot repurchase shares of common stock, subject to limited exceptions, without the prior written consent of Alloy Parent. (See Note 15. Agreement and Plan of Merger).

 Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (Continued)

 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, 2019, and reinvestment of dividends.

 2019
 2020
 2021
 2022
 2023
 2024

 ALLETE
 $100
 $80
 $88
 $90
 $89
 $99

 S&P 500 Index
 $100
 $118
 $152
 $125
 $157
 $197

 Philadelphia Utility Index
 $100
 $103
 $121
 $122
 $111
 $134

 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 7 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, operates, or has developed more than 1,600 megawatts of wind energy generation in five major energy markets and eight states across the U.S. 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.

 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, 2024, 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.

 On May 5, 2024, ALLETE entered into the Merger Agreement. The Merger Agreement provides that, on and subject to the conditions set forth therein, Alloy Merger Sub will merge with and into ALLETE, with ALLETE continuing as the surviving corporation in the Merger and becoming a subsidiary of Alloy Parent. (See Note 15. Agreement and Plan of Merger.)

 2024 Financial Overview

 The following net income discussion summarizes a comparison of the year ended December 31, 2024, to the year ended December 31, 2023.

 Net income attributable to ALLETE in 2024 was $179.3 million, or $3.10 per diluted share, compared to $247.1 million, or $4.30 per diluted share, in 2023. Net income in 2024 includes transaction expenses of $22.6 million after-tax, or $0.39 per share, related to the Merger. (See Note 15. Agreement and Plan of Merger.) Net income in 2023 included transaction expenses of $3.6 million after-tax, or $0.06 per share, related to the Merger and a $40.5 million, or $0.71 per share, after-tax gain recognized for a favorable arbitration ruling involving a subsidiary of ALLETE Clean Energy. (See Note 9. Commitments, Guarantees and Contingencies.) Earnings per share dilution in 2024 was $0.02 due to additional shares of common stock outstanding in 2024 compared to 2023.

 Regulated Operations net income attributable to ALLETE was $160.9 million in 2024, compared to $147.2 million in 2023. Net income at Minnesota Power was higher compared to 2023 reflecting the implementation of interim rates on January 1, 2024, net of reserves related to Minnesota Power's rate case settlement (see Note 4. Regulatory Matters), and higher transmission margins, which were partially offset by higher depreciation and property tax expenses as well as lower margins from industrial customers. Net income at SWL&P was lower than 2023 primarily due to higher operating and maintenance expenses. Our after-tax equity earnings in ATC were higher than 2023 reflecting period over period changes in ATC's estimate of a refund liability related to the FERC decision on MISO return on equity complaints in 2024. (See Note 6. Equity Investments.)

 ALLETE Clean Energy net income attributable to ALLETE was $17.8 million in 2024 compared to $71.7 million in 2023. Net income in 2024 includes a $3.5 million after-tax gain on the sale of the Whitetail wind project. Net income in 2023 reflected a $44.3 million after-tax gain recognized for a favorable arbitration ruling involving a subsidiary of ALLETE Clean Energy. Net income in 2023 also included the gain on sale of the Red Barn project in 2023 of $4.3 million after-tax and higher interest income related to interest awarded as part of the arbitration ruling. Net income in 2024 and 2023 reflected a forced outage located near its Caddo wind energy facility beginning in the fourth quarter of 2023 through the second quarter of 2024 resulting in lower earnings.

 Corporate and Other net income attributable to ALLETE was $0.6 million in 2024 compared to $28.2 million in 2023. Net income in 2024 includes transaction expenses of $22.6 million after-tax related to the Merger (See Note 15. Agreement and Plan of Merger), and also reflects lower earnings from Minnesota solar projects as investment tax credits were recognized in 2023 for the projects and lower earnings from ALLETE Properties reflecting fewer land sales in 2024 compared to 2023. Net income in 2023 reflects a $3.8 million after-tax expense for the consolidated income tax impact resulting from the gain on the favorable arbitration ruling. Net income at New Energy was $20.2 million in 2024 compared to $17.6 million in 2023.

 2024 Compared to 2023

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

 2024
 2023

 Operating Revenue – Utility
 $1,242.7
 $1,238.3

 479.7
 484.3

 64.6
 88.2

 250.0
 247.1

 196.3
 179.2

 52.5
 44.5

 199.6
 195.0

 (66.1)
 (63.9)

 26.5
 23.1

 Other Income
 18.5
 15.4

 Income Before Income Taxes
 178.5
 169.6

 Income Tax Expense (Benefit)
 17.6
 22.4

 $160.9
 $147.2

 2024 Compared to 2023 (Continued)
 Regulated Operations (Continued)

 Operating Revenue – Utility increased $4.4 million from 2023 primarily due to the implementation of interim rates, net of reserves, in 2024, and higher fuel adjustment clause recoveries. These increases were partially offset by lower transmission revenue, kWh sales and gas sales as well as a reduction related to the expected utilization of North Dakota investment tax credits.

 Interim retail rates for Minnesota Power, subject to refund, were approved by the MPUC and became effective January 1, 2024, resulting in revenue of $41.1 million, net of reserves related to Minnesota Power's rate case settlement and rider revenue incorporated into base rates. (See Note 4. Regulatory Matters.)

 Fuel adjustment clause revenue increased $3.4 million due to higher fuel and purchased power costs attributable to retail and municipal customers. (See Fuel, Purchased Power and Gas – Utility.)

 Lower kWh sales decreased revenue by $15.3 million from 2023 reflecting lower sales to residential, commercial and industrial customers as well as lower sales to other power suppliers. Sales to residential and commercial customers decreased from 2023 primarily due to milder weather in 2024 compared to 2023. Sales to industrial customers decreased primarily due to lower sales to taconite and pipeline customers, partially offset by higher sales to paper, pulp and secondary wood product customers. 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 reflecting fewer market sales, partially offset by higher market prices in 2024 compared to 2023.

 Kilowatt-hours Sold

 2024
 2023
 Quantity
Variance
 %
Variance

 Regulated Utility

 Retail and Municipal

 Residential
 1,069
 1,089
 (20)
 (1.8)

 Commercial
 1,322
 1,347
 (25)
 (1.9)

 Industrial
 7,022
 7,044
 (22)
 (0.3)

 Municipal
 0.6

 Total Retail and Municipal
 9,882
 9,946
 (64)
 (0.6)

 Other Power Suppliers
 2,680
 2,819
 (139)
 (4.9)

 Total Regulated Utility Kilowatt-hours Sold
 12,562
 12,765
 (203)
 (1.6)

 Revenue from electric sales to taconite and mining customers accounted for 32 percent of regulated operating revenue in 2024 (32 percent in 2023). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of regulated operating revenue in 2024 (5 percent in 2023). Revenue from electric sales to pipelines and other industrial customers accounted for 11 percent of regulated operating revenue in 2024 (11 percent in 2023).

 Transmission revenue decreased $13.8 million primarily due to lower MISO-related revenue. Transmission revenue in 2024 included the refund of MISO transmission payments that were over collected during 2023. (See Transmission Services – Utility).

 Cost recovery rider revenue decreased by $8.1 million from 2023 due to period over period changes in the estimate of North Dakota investment tax credits expected to be utilized by Minnesota Power. If the estimate of North Dakota investment tax credits expected to be utilized by Minnesota Power increases, an income tax benefit is recognized and a corresponding decrease in revenue is recognized to offset the impact of higher North Dakota investment tax credits on income tax expense.

 Revenue from gas sales at SWL&P decreased $3.7 million reflecting fewer gas sales resulting from warmer winter weather and lower gas prices in 2024 compared to 2023. (See Fuel, Purchased Power and Gas – Utility.)

 2024 Compared to 2023 (Continued)
 Regulated Operations (Continued)

 Operating Expenses decreased $0.2 million from 2023.

 Fuel, Purchased Power and Gas – Utility expense decreased $4.6 million, or 1 percent, from 2023 primarily due to lower kWh sales as well as lower gas sales and prices. These decreases were partially offset by less company-owned generation in 2024 compared to 2023 resulting in more sales being supplied through higher cost purchased power.

 Transmission Services – Utility expense decreased $23.6 million, or 27 percent, from 2023 primarily due to lower MISO-related expense. Transmission Services – Utility expense in 2024 included the refund of MISO transmission payments that were over billed during 2023. (See Operating Revenue – Utility).

 Operating and Maintenance expense increased $2.9 million, or 1 percent, from 2023 primarily due to higher salaries and wages, benefit costs, and contract and professional services. These increases were partially offset by a reduction to expense for liquidated damages related to contractor underperformance under a maintenance agreement.

 Depreciation and Amortization expense increased $17.1 million, or 10 percent, from 2023 primarily due to the impact of estimated compliance costs related to the EPA's CCR Legacy Impoundment Rule finalized in May 2024 and a higher plant in service balance in 2024.

 Taxes Other than Income Taxes increased $8.0 million, or 18 percent, from 2023 primarily due to higher property tax expense. Property tax expense in 2023 included the favorable impact of an updated estimate for 2022 property tax expense recorded in 2023.

 Interest Expense increased $2.2 million, or 3 percent, from 2023 primarily due to higher interest rates and interest on Minnesota Power's reserve for interim rate refunds in 2024.

 Equity Earnings increased $3.4 million, or 15 percent, from 2023 primarily due to period over period changes in ATC's estimate of a refund liability related to the FERC decision on MISO return on equity complaints in 2024. (See Note 6. Equity Investments.)

 Other Income increased $3.1 million from 2023 reflecting lower pension and other postretirement benefit plan non-service costs.

 Income Tax Expense decreased $4.8 million from 2023. This is primarily due to the updated expected future use of North Dakota investment tax credits.

 2024 Compared to 2023 (Continued)

 2024
 2023

 $79.3
 $413.4

 Other – Non-utility (a)

 5.0
 5.1

 18.3
 342.2

 46.5
 52.1

 57.5
 57.5

 10.4
 10.0

 Operating Loss
 (48.4)
 (43.3)

 (0.3)
 (0.8)

 Other Income (b)

 7.5
 68.0

 Income (Loss) Before Income Taxes
 (41.2)
 23.9

 Income Tax Expense (Benefit)
 (15.6)
 2.7

 Net Income (Loss)
 (25.6)
 21.2

 Net Loss Attributable to Non-Controlling Interest (b)

 (43.4)
 (50.5)

 $17.8
 $71.7

 (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 decreased $334.2 million from 2023 primarily due to the sales of ALLETE Clean Energy's Northern Wind and Red Barn projects in 2023, partially offset by the sale of ALLETE Clean Energy's Whitetail wind project in 2024. In addition, operating revenue in 2024 was negatively impacted by a network outage located near Caddo. The network outage began in the fourth quarter of 2023 resulting from a forced outage of a substation and the transmission lines feeding that substation. This forced outage increased congestion experienced by Caddo resulting in lower kWh sales and pricing. The forced outage was resolved in June 2024. (See Outlook - ALLETE Clean Energy.)

 Year Ended December 31,

 2024
 2023

 Production and Operating Revenue
 kWh
 Revenue
 kWh
 Revenue

 Wind Energy Regions

 East
 235.4
 $21.3
 224.0
 $21.2

 Midwest
 560.3
 18.7
 560.9
 18.4

 South
 1,395.3
 6.6
 1,720.8
 16.8

 West
 773.9
 14.8
 714.1
 13.6

 Total Wind Energy Facilities
 2,964.9
 61.4
 3,219.8
 70.0

 Sale of Wind Energy Facility
 —
 22.9
 —
 348.5

 Total Production and Operating Revenue
 2,964.9
 $84.3
 3,219.8
 $418.5

 2024 Compared to 2023 (Continued)
 ALLETE Clean Energy (Continued)

 Cost of Sales - Non-utility decreased $323.9 million from 2023 primarily due to the sales of ALLETE Clean Energy's Northern Wind and Red Barn projects, partially offset by the sale of ALLETE Clean Energy's Whitetail wind project.

 Operating and Maintenance expense decreased $5.6 million, or 11 percent, from 2023 primarily due to business interruption insurance proceeds at Diamond Spring in 2024 related to a transformer outage in the first half of 2024.

 Other Income decreased $60.5 million from 2023 primarily due to a $58.4 million gain recognized for a favorable arbitration ruling in 2023 involving a subsidiary of ALLETE Clean Energy and higher interest income related to $5.1 million of interest awarded as part of the favorable arbitration ruling. (See Note 6. Commitments, Guarantees, and Contingencies.)

 Income Tax Expense decreased $18.3 million from 2023 primarily due to lower pre-tax income in 2024 compared to 2023.

 Net Loss Attributable to Non-Controlling Interest decreased $7.1 million from 2023 reflecting lower availability at ALLETE Clean Energy's tax equity financed wind energy facilities resulting from the impacts of a network outage near Caddo and a transformer outage at Diamond Spring. This decrease was partially offset by a higher production tax credit rate, as determined by the Internal Revenue Service, in 2024 compared to 2023.

 Operating Revenue decreased $20.2 million, or 9 percent, from 2023 reflecting lower revenue from New Energy and lower revenue from ALLETE Properties reflecting fewer land sales in 2024 compared to 2023.

 Net Income Attributable to ALLETE was $0.6 million in 2024 compared to $28.2 million in 2023. Net income in 2024 includes transaction expenses of $22.6 million after-tax related to the Merger (See Note 15. Agreement and Plan of Merger), and also reflects lower earnings from Minnesota solar projects as investment tax credits were recognized in 2023 for the projects and lower earnings from ALLETE Properties reflecting fewer land sales in 2024 compared to 2023. Net income in 2023 reflects a $3.8 million after-tax expense for the consolidated income tax impact resulting from the gain on the favorable arbitration ruling. Net income at New Energy was $20.2 million in 2024 compared to $17.6 million in 2023.

 Income Taxes – Consolidated

 For the year ended December 31, 2024, the effective tax rate was an expense of 3.7 percent (expense of 13.5 percent for the year ended December 31, 2023). The lower effective tax rate for 2024 is primarily due to lower pre-tax income. (See Note 11. Income Tax Expense.)

 2023 Compared to 2022

 The comparison of the results of operations for the years ended December 31, 2023 and 2022, is included in Management's Discussion in the Annual Report on Form 10-K for the year ended December 31, 2023.

 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, 2024, was approximately 57 percent equity securities, 40 percent fixed income and 3 percent real estate. Our postretirement health and life asset allocation as of December 31, 2024, was approximately 67 percent equity securities, and 33 percent fixed income. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2024, we used weighted average expected long-term rates of return of 6.84 percent in our actuarial determination of our pension expense and 6.28 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 $2.1 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 2024, we used weighted average discount rates of 5.38 percent and 5.42 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 $0.2 million, pre-tax.

 The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2024, 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.

 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 12.5 percent, cash flow forecasts through 2033, 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, 2024.

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

 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.

 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 2025. ALLETE expects its businesses to generally provide regulated, contracted or recurring revenues, and to support sustained growth in net income and cash flow.

 In August 2022, the Inflation Reduction Act was signed into law. We believe our businesses will benefit from certain provisions of this law including from the extension and transferability of production tax credits and investment tax credits, among others. We have sold certain tax credits generated in 2023 and 2024, and we plan to continue selling certain tax credits generated in 2025 and beyond. We do not currently anticipate any impact from the new alternative minimum tax. We will continue to assess the impact of the law as additional implementation guidance becomes available and monitor any changes related to new public policies.

 Minnesota Carbon-Free Legislation. On February 7, 2023, the Minnesota Governor signed a law that updated 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. Ongoing progress towards compliance with Minnesota's Carbon Free Standard is evaluated in the IRP proceedings at the MPUC. Minnesota Power's next IRP will be filed in March 2025 and discuss progress towards compliance with the 2040 law.

 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 is making significant progress toward 100 percent carbon-free energy supply. (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.

 2024 Minnesota General Rate Case. On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $64 million, net of rider revenue, beginning January 1, 2024, subject to refund.

 On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power's refund calculation.

 2022 Minnesota General Rate Case. Minnesota Power appealed with the Minnesota Court of Appeals (Court) specific aspects of the MPUC's February 2023 and May 2023 rate case orders for the ratemaking treatment of Taconite Harbor and Minnesota Power's prepaid pension asset. On September 9, 2024, the Court affirmed the MPUC's Taconite Harbor treatment, but reversed and remanded the treatment of Minnesota Power's prepaid pension asset back to the MPUC. The Court directed the MPUC to determine the amount of Minnesota Power's prepaid pension asset to be included in rate base. The MPUC has not yet determined the next procedural steps in implementing the Court's decision.

 2024 Wisconsin General Rate Case. On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would increase rates by approximately 5.90 percent for retail customers and generate an estimated $7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025.

 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 56 percent of our regulated utility kWh sales in 2024 (55 percent in 2023 and 52 percent in 2022) were made to our industrial customers. We expect industrial sales of approximately 6.9 million MWh in 2025 (7.0 million MWh in 2024 and 7.0 million MWh in 2023). (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 steelmaking 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, approximately 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 76 percent of capacity in 2024 (75 percent in 2023 and 78 percent in 2022). 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 2025 will increase by approximately 2 percent compared to 2024.

 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. The Minnesota Department of Revenue Mineral Tax Office expects taconite production from our taconite customers to be approximately 34 million tons in 2025. We estimate that a one million ton change in Minnesota Power's taconite customers' production would impact our annual earnings per share by approximately $0.07, 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 completed a $150 million investment to produce direct reduced-grade (DR-grade) pellets at its Keetac plant in late 2023. USS Corporation broke ground on the project in the third quarter of 2022, and confirmed the first shipment of DR-grade pellets in 2024. This investment enables 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 annually produce approximately 15 million tons of blast furnace-grade pellets at its Minntac plant and 5 million tons of blast-furnace grade pellets, or 4 million tons of DR-grade pellets, at its Keetac plant.

 On December 18, 2023, USS Corporation announced it entered into a definitive agreement in which Nippon Steel will acquire all of the shares of USS Corporation. USS Corporation expected the transaction to close by the end of 2024, subject to regulatory approvals, at which time USS Corporation stated it will continue to operate under the U.S. Steel brand name and will maintain its headquarters in Pittsburgh, Pennsylvania. On January 3, 2025, President Biden issued an order blocking the transaction, a decision currently being challenged in court.

 On January 27, 2025, USS Corporation exercised its rights under its electric service agreement with Minnesota Power to provide a four-year notice of termination. Minnesota Power and USS Corporation are working together to meet USS Corporation's evolving energy needs. Absent any other action by the parties, the termination of the current electric service agreement would be effective January 27, 2029, and USS Corporation would become a non-contract large power customer of Minnesota Power.

 Industrial Customers (Continued)

 Cleveland-Cliffs, Inc. (Cliffs). Cliffs is the largest flat-rolled steel producer and the largest iron ore pellet producer in North America, and is also Minnesota Power's largest customer. Its acquisition in 2020 of substantially all of the operations of ArcelorMittal USA LLC and its subsidiaries 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. The acquisition 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. In 2024, Cliffs announced and completed an acquisition of Stelco Holdings, enhancing Cliffs' position as the largest flat-rolled steel producer in North America, diversifying Cliffs' end-markets, and expanding its geographical presence in Canada.

 Northshore Mining. Cliffs idled all production at its Northshore mine in 2022, and subsequently resumed partial pellet plant production in April 2023. Cliffs indicated it will continue to utilize Northshore Mining as a swing facility. 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.

 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. On May 25, 2023, the Minnesota Executive Council approved state mineral leases near Nashwauk, Minnesota, with Cliffs, the majority owner of Hibbing Taconite. Cliffs had stated that these leases would provide Hibbing Taconite with more than two decades of additional mineral reserves. In October of 2023, Mesabi Metallics issued a notice of termination of a private iron ore mineral lease agreement previously held by Cliffs, a decision that was affirmed in arbitration in 2024. Cliffs has stated that without these leases, the future of Hibbing Taconite is once again in question. Prior to the state mineral leases being awarded, Hibbing Taconite had proven mineral reserves to support its operations through 2026. Hibbing Taconite has the capability of producing 8 million tons of taconite annually.

 Minnesota Sulfate Wild Rice Water Quality Standard. In April, 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. In September, 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 2025 at the major paper and pulp mills we serve to be at similar levels as in 2024.

 Sofidel. ST Paper, a former Large Power Customer of Minnesota Power, sold its paper mill in Duluth, Minnesota to Sofidel, a privately held Italian multinational company, in the first quarter of 2024. In the third quarter of 2024, Sofidel announced plans to invest between $200 million and $250 million to add a conversion facility and automated warehouse to the tissue plant.

 Pipeline and Other Industries.

 Cenovus Energy. In 2023, Cenovus Energy announced that it had commenced a restart of the facility and resumed full operations in 2024 following a rebuild from a fire in 2018.

 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, continuing its commitment to climate, customers and communities through its EnergyForward strategy. This vision builds on Minnesota Power's achievement in 2020 of providing 50 percent renewable energy to its customers. In 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. Minnesota Power is working with various stakeholders and participating in the regulatory process to implement this legislation. (See Item 1. Business – Regulated Operations – Minnesota Legislation.)

 2021 IRP. In February 2021, Minnesota Power filed its latest IRP, which was approved by the MPUC in a January 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 in March 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.

 Nemadji Trail Energy Center. Minnesota Power has 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 upon the completion of the facility pursuant to the capacity dedication agreement.

 Renewable Energy. Minnesota Power continues to execute its renewable energy strategy and is currently supplying 55 percent of its energy by renewable energy sources. Minnesota Power is also making significant progress toward 100 percent carbon-free energy supply. (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. (See Transmission.)

 Wind Energy Request For Proposals. On February 15, 2024, Minnesota Power issued a RFP for up to 400 MW of wind energy resources.

 EnergyForward (Continued)

 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 facilities consist of a 10 MW solar energy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, and a 40 kW solar array located in Duluth, Minnesota. Minnesota Power also purchases solar energy from approximately 20 MW of solar energy facilities located in Minnesota that are owned by an ALLETE subsidiary, and a 1 MW community solar garden in northeastern Minnesota, which is owned and operated by a third party. SWL&P owns and operates a 470 kW solar array as part of a community solar garden in Superior, Wisconsin, that went into service in 2023.

 Solar Energy Request For Proposals. On November 15, 2023, Minnesota Power issued a RFP for up to 300 MW of solar energy resources, which were accepted through January 17, 2024. On September 23, 2024, Minnesota Power announced plans to build an 85 MW solar project and a 119.5 MW solar project in northern Minnesota, both of which are expected to be in service in mid-2027, subject to MPUC approval.

 Distributed Solar Energy Request for Proposals. On January 30, 2025, Minnesota Power issued a RFP seeking distributed solar projects as part of its compliance with Minnesota's distributed solar energy standard. The RFP seeks proposals for solar generating facilities of 10 MW or less that will be connected to Minnesota Power's distribution system.

 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 investments to enhance our own transmission facilities and investments in other transmission assets (individually or in combination with others) and our investment in ATC. See also Item 1. Business – Regulated Operations – Transmission and Distribution.

 North Plains Connector Development Agreement. In December 2023, ALLETE and Grid United LLC, an independent transmission company, signed development agreements for the North Plains Connector project. The project is a new, approximately 400-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 capital cost is expected to be approximately $3.2 billion. On August 6, 2024, the U.S. Department of Energy awarded a $700 million grant to the project. ALLETE expects to pursue up to 35 percent ownership and will be positioned to oversee the line's operation. The companies began project permitting in 2023 as they work toward a planned in-service date as early as 2032, pending regulatory and other necessary approvals.

 Duluth Loop Reliability Project. In October 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 was granted and a route permit was issued by the MPUC on April 3, 2023. The Duluth Loop Reliability Project is expected to be completed and in service by late 2026 to early 2027, with an estimated cost of $50 million to $70 million.

 Transmission (Continued)

 HVDC Transmission System Project. On June 1, 2023, Minnesota Power submitted an application for a certificate of need and route permit with the MPUC to replace aging critical infrastructure and modernize the terminal stations of its HVDC transmission line. In an October 25, 2024, order, the MPUC approved the certificate of need and route permit. Minnesota Power uses the 465-mile, 250-kV HVDC 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. The HVDC transmission system project is expected to improve reliability of the transmission system, improve system resiliency, expand the operating capacity of the HVDC terminals, and replace critical infrastructure. Construction on the Minnesota end of the project will begin in early 2025. Construction on the North Dakota end of the project will begin later in 2025, pending regulatory approvals in North Dakota. The project will be placed in-service between 2028 and 2030. The project is estimated to cost between $800 million and $940 million. On October 18, 2023, the U.S. Department of Energy awarded a $50 million grant to Minnesota Power for this project, which will be used to prepare the HVDC transmission system for future expansion and help reduce project costs to customers. In addition, this project was awarded $15 million in state funding as part of an energy and climate budget bill passed by the Minnesota Legislature in 2023. Further, Minnesota Power's application to the Minnesota Department of Commerce (DOC) State Competitiveness Fund Match Program received notification the DOC is reserving $10 million as a cost share for the project. In total, Minnesota Power has been awarded $75 million in federal and state dollars in support of the project.

 Northland Reliability Project. Minnesota Power and Great River Energy announced in July 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 in August 2022. This joint project is part of a portfolio of transmission projects approved in July 2022 by MISO as part of the first phase of its Long Range Transmission Plan. Planning for the approximately $970 million to $1,350 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 MPUC will determine the final route as well as cost recovery for Minnesota Power's approximately 50 percent estimated share of the project. On August 4, 2023, Minnesota Power and Great River Energy submitted an application for a certificate of need and route permit with the MPUC, which were approved by the MPUC at a hearing on January 23, 2025. On May 10, 2024, the FERC approved Minnesota Power's request to recover on construction work in progress related to this project from Minnesota Power's wholesale customers. Subject to regulatory approvals, the transmission line is expected to be in service in 2030.

 Big Stone South – Alexandria – Big Oaks Transmission Project. Northern States Power, Great River Energy, Minnesota Power, Otter Tail Power Company, and Missouri River Energy Resources (Project Developers) announced in July 2022 their intent to build a 150-mile, 345-kV transmission line to improve reliability in North Dakota, South Dakota, and western and central Minnesota. This joint project is part of a portfolio of transmission projects approved in July 2022 by MISO as part of the first phase of its Long Range Transmission Plan. A Notice of Intent to Construct, Own and Maintain the transmission line was filed with the MPUC in October 2022. On September 29, 2023, the Project Developers submitted an application for a certificate of need and route permit with the MPUC, which was approved on October 3, 2024. The project is in its early stages and is expected to cost between $600 million and $700 million. Minnesota Power has asset ownership in the Alexandria – Big Oaks portion of the project, with start of construction following the certificate of need approval on October 3, 2024. Minnesota Power is a 16.5 percent owner of this portion of the project and will invest at this level for the entire portion of the project. On May 10, 2024, the FERC approved Minnesota Power's request to recover on construction work in progress related to this project from Minnesota Power's wholesale customers. The Minnesota Power portion of this transmission line is expected to be in service in 2027.

 Second Phase of MISO Long Range Transmission Plan. Minnesota Power and SWL&P are participating in several projects identified in the second phase of the MISO Long Range Transmission Plan that was approved on December 12, 2024, including the Bison – Alexandria 345kV project, the Maple River – Cuyuna 345kV project, the Iron Range – St Louis County – Arrowhead 345kV project, and the Stinson MSSSC project. Notices of Intent to Construct, Own and Maintain the Bison – Alexandria 345kV project, the Maple River – Cuyuna 345 kV project, and the Iron Range – St Louis County – Arrowhead 345kV project were filed with the MPUC on February 7, 2025.

 Bison – Alexandria 345kV project. This transmission line is closely related to the Alexandria – Big Oaks line noted previously and is anticipated to have the same ownership structure. MISO found that this project along with others in northern Minnesota provide outlets for generation from the west, supports large power transfers to load centers, and reduces congestion. The project in total is estimated to cost over $200 million and is expected to be completed by 2032.

 Transmission (Continued)

 Maple River – Cuyuna 345 kV project. This transmission line is a new, 166-mile 345-kV circuit that will connect the Maple River Substation near Fargo, ND to the Cuyuna Series Compensation Station near Riverton, MN. Minnesota Power is the owner of the Cuyuna Series Compensation Station in Minnesota, which is being constructed as part of the Northland Reliability Project, a joint project with Great River Energy. Otter Tail Power Company is the owner of the Maple River Substation in North Dakota. The project in total is estimated to cost approximately $910 million and is expected to be completed by 2033.

 Iron Range – St. Louis County – Arrowhead 345kV project. This transmission line is a new, 63-mile 345-kV circuit that will connect the Iron Range Substation near Grand Rapids, MN to the St. Louis County Substation near Hermantown, MN, and then to the Arrowhead 345 kV Substation, also near Hermantown, MN. Minnesota Power is the owner of the Iron Range and St. Louis County substations. ATC is the owner of the Arrowhead 345 kV Substation. The project in total is estimated to cost approximately $370 million and is expected to be completed by 2032.

 Stinson MSSSC project. This project involves modification and expansion of the existing Stinson Substation in Superior, Wisconsin to accommodate a new modular static synchronous series compensator (MSSSC) system and associated substation equipment. The MSSSC system is a type of grid-enhancing technology that will provide power flow capability to replace the existing Stinson phase shifting transformer. The project was identified as an underlying system improvement associated with LRTP Project #21 (Iron Range-St Louis County-Arrowhead Project) in the second phase of the MISO Long Range Transmission Plan that was approved on December 12, 2024. SWL&P is the owner of the Stinson Substation. The project is estimated to cost approximately $58 million and is expected to be completed by 2032.

 Investment in ATC. ATC's most recent 10-year transmission assessment, which covers the years 2024 through 2033, identifies a need for between $8.9 billion and $10.9 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 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, congestion 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 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, advance and expand its project pipeline, and explore other renewable energy opportunities to further enhance its service offerings, growth and profitability.

 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 disclosed in Item 1. Business.

 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 575 MW in its history, totaling more than $1.4 billion of capital. New Energy currently has a robust project pipeline with greater than 2,000 MW of renewable projects in development across over 20 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. New Energy will continue its current strategy of developing, owning and operating 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 upon completion of the facility 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 will be responsible for approximately 20 percent. South Shore Energy's portion of NTEC project costs incurred through December 31, 2024, is approximately $10 million.

 BNI Energy. In 2024, BNI Energy sold 3.8 million tons of coal (4.0 million tons in 2023) and anticipates 2025 sales will be similar to 2024. 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 2024. 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 that our effective tax rate will be lower than the combined statutory rate over the next 5 to 10 years due to tax credits attributable to our wind and solar energy generation.

 Liquidity and Capital Resources

 Liquidity Position. ALLETE is well-positioned to meet its liquidity needs. As of December 31, 2024, we had cash and cash equivalents of $32.8 million, $325.8 million in available consolidated lines of credit, 2.1 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, the option (per the Merger Agreement) to request that Alloy Parent purchase up to a total of $300 million of preferred stock of ALLETE in the second half of 2025 (see Securities), and a debt-to-capital ratio of 35 percent.

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

 2024
 %
 2023
 %
 2022
 %

 ALLETE Equity
 $2,848.0
 $2,809.6
 $2,691.9

 Non-Controlling Interest in Subsidiaries
 542.1
 597.0
 656.4

 Short-Term and Long-Term Debt (a)

 1,808.0
 1,799.4
 1,929.1

 Redeemable Non-Controlling Interest
 0.4
 —
 0.5
 —
 —
 —

 $5,198.5
 $5,206.5
 $5,277.4

 (a) Excludes unamortized debt issuance costs.

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

 2024
 2023
 2022

 Cash, Cash Equivalents and Restricted Cash at Beginning of Period
 $79.4
 $40.2
 $47.7

 Cash Flows from (used in)

 Operating Activities
 457.1
 585.3
 221.3

 Investing Activities
 (340.7)
 (283.6)
 (384.0)

 Financing Activities
 (140.6)
 (262.5)
 155.2

 Change in Cash, Cash Equivalents and Restricted Cash
 (24.2)
 39.2
 (7.5)

 Cash, Cash Equivalents and Restricted Cash at End of Period
 $55.2
 $79.4
 $40.2

 Operating Activities. Cash provided by operating activities was lower in 2024 compared to 2023 reflecting cash proceeds from the sales of ALLETE Clean Energy's Northern Wind and Red Barn projects in 2023, cash received from the favorable arbitration award by a subsidiary of ALLETE Clean Energy in 2023, higher cash contributions to defined benefit pension in 2024, and timing of recovery under Minnesota Power's fuel adjustment clause. These decreases were partially offset by proceeds from the sale of renewable tax credits in 2024.

 Cash provided by operating activities was higher in 2023 compared to 2022 reflecting cash proceeds from the sales of ALLETE Clean Energy's Northern Wind and Red Barn projects in 2023, cash received from the favorable arbitration award by a subsidiary of ALLETE Clean Energy in 2023, lower payments for inventories in 2023 related to the Northern Wind and Red Barn projects, and timing of recovery under Minnesota Power's fuel adjustment clause. Cash provided by operating activities in 2023 also increased due to the timing of recovery under Minnesota Power's fuel adjustment clause.

 Investing Activities. Cash used in investing activities was higher in 2024 compared to 2023 reflecting more payments for additions to property, plant and equipment compared to 2023, partially offset by state cash grants received for our HVDC Transmission System Project in 2024. (See Outlook.)

 Cash used in investing activities was lower in 2023 compared to 2022 reflecting cash payments for the acquisition of New Energy in 2022. This decrease was partially offset by more payments for additions to property, plant and equipment in 2023 compared to 2022.

 Financing Activities. Cash used in financing activities was lower in 2024 compared to 2023 reflecting higher proceeds from the issuance of long-term debt compared in 2024, partially offset by higher repayments of long-term debt in 2024.

 Cash used in financing activities in 2023 reflected lower proceeds from the issuance of common stock and the issuance of long-term debt, and lower proceeds from the issuance of non-controlling interest in subsidiaries compared to 2022.

 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, 2024, we had consolidated bank lines of credit aggregating $362.0 million ($423.1 million as of December 31, 2023), most of which expire in January 2027. We had $16.2 million outstanding in standby letters of credit and $20.0 million outstanding draws under our lines of credit as of December 31, 2024 ($19.4 million in standby letters of credit and $34.1 million outstanding draws as of December 31, 2023). We also have other credit facility agreements in place that provide the ability to issue up to $180.0 million in standby letters of credit. As of December 31, 2024, we had $118.4 million outstanding in standby letters of credit under these agreements.

 In addition, as of December 31, 2024, we had 2.4 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. The Merger Agreement also provides that ALLETE may notify Alloy Parent of our intent to raise equity capital of up to a total of $300 million in the second half of 2025, subject to certain parameters. If Alloy Parent declines to participate in the equity capital raises or fails to provide timely notice with respect thereto, ALLETE will have the right to issue ALLETE common stock in the public markets for an amount equal to any unfunded amounts under such equity capital raises up to certain limits. (See Note 15. Agreement and Plan of Merger.)

 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, 2024. For the year ended December 31, 2024, no shares of common stock were issued under this agreement (none in 2023; none in 2022).

 During the year ended December 31, 2024, 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 $12.9 million (0.3 million shares for net proceeds of $14.9 million in 2023; 0.3 million shares for net proceeds of $16.2 million in 2022). See Note 10. Common Stock and Earnings Per Share for additional detail regarding ALLETE's equity securities.

 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, 2024, we made $25.0 million in cash contributions to the defined benefit pension plans. On January 15, 2025, we contributed $19.1 million in cash to the defined benefit pension plans, and do not expect to make additional cash contributions to the defined benefit pension plans in 2025. We do not expect to make any contributions to the defined benefit postretirement health and life plans in 2025. (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.)

 Liquidity and Capital Resources (Continued)
 Contractual Obligations and Commercial Commitments (Continued)

 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.)

 Operating and Finance Lease Obligations. ALLETE has certain operating and finance 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 (a)

 Moody's

 Issuer Credit Rating
 BBB
 Baa1

 Commercial Paper
 A-2
 P-2

 First Mortgage Bonds
 (b)
 A2

 (a) On May 7, 2024, S&P Global Ratings revised its outlook on ALLETE to negative from stable and affirmed all of its ratings on ALLETE. S&P Global Ratings cited the possibility for higher leverage and weaker financial measures because of the Merger as its rationale for issuing the negative outlook.
 (b) 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 2024, we paid out 91 percent (63 percent in 2023; 77 percent in 2022) of our per share earnings in dividends. On January 30, 2025, our Board of Directors declared a dividend of $0.73 per share, which is payable on March 1, 2025, to shareholders of record at the close of business on February 14, 2025.

 Under the Merger Agreement, the Company has agreed not to declare or pay dividends except for quarterly cash dividends payable by us in respect of shares of our common stock on a schedule consistent with our past practices in an amount not to exceed 5 percent per share more than the dividend payable during the prior 12-month period, subject to certain other exceptions. (See Note 15. Agreement and Plan of Merger).

 Capital Requirements

 ALLETE's projected capital expenditures for the years 2025 through 2029 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
 2025
 2026
 2027
 2028
 2029
 Total

 High kV Transmission Expansion (a)

 $90
 $200
 $615
 $635
 $265
 $1,805

 Solar RFP (b)

 —

 Wind RFP (b)

 —
 —

 Storage (b)

 —

 Base & Other
 1,320

 1,320
 1,155
 4,610

 ALLETE Clean Energy (c)

 South Shore Energy (d)

 —

 Other

 Total Capital Expenditures (e)

 $605
 $940
 $1,410
 $1,240
 $810
 $5,005

 (a)This includes capital expenditures for the HVDC modernization, Northland Reliability, Duluth Loop, Big Stone South transmission projects and several projects identified in the second phase of the MISO Long Range Transmission Plan that was approved on December 12, 2024. (See Outlook – Transmission.)
 (b)These capital expenditures are part of Minnesota Power's clean-energy transition plans, which include its progress toward 100 percent carbon-free energy supply, 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.)
 (c)Capital expenditures do not include costs related to developing projects that will be sold upon completion as these costs are accounted for as inventory and reflected in Inventories – Net on the Consolidated Balance Sheet.
 (d)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.
 (e)These amounts do not include capital expenditures for projects considered to be in their preliminary stages.

 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, 2024, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.

 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, 2024:

 Expected Maturity Date

 Interest Rate Sensitive
Financial Instruments
 2025
 2026
 2027
 2028
 2029
 Thereafter
 Total

 Fixed Rate – Millions
 $66.9
 $80.2
 $162.5
 $55.8
 $220.3
 $1,174.5
 $1,760.2
 $1,620.2

 Average Interest Rate – %
 5.4
 3.5
 4.5
 3.8
 4.9
 4.5
 4.5

 Variable Rate – Millions
 $27.8
 —
 $20.0
 —
 —
 —
 $47.8
 $47.8

 Average Interest Rate – %
 3.7
 —
 5.7
 —
 —
 —
 4.5

 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, 2024, an increase of 100 basis points in interest rates would impact the amount of pre-tax interest expense by $0.5 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, 2024.

 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.

 Item 8. Financial Statements and Supplementary Data

 See our Consolidated Financial Statements as of December 31, 2024 and 2023, and for the years ended December 31, 2024, 2023 and 2022, 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, 2024, 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, 2024.

 The effectiveness of the Company's internal control over financial reporting as of December 31, 2024, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 Changes in Internal Controls

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

 Item 9B. Other Information

 Trading Plans. For the three months ended December 31, 2024, no director or officer of the Company adopted, modified or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.

 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Not applicable.

 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 2025 Annual Meeting of Shareholders (2025 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 2025 Proxy Statement will be filed with the SEC within 120 days after the end of our 2024 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 and Human Capital 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.

 Insider Trading Policies. The information required by this Item for disclosure of the Company's insider trading policies and procedures and disclosure of certain options awarded close in time to the release of material nonpublic information is incorporated by reference herein from our 2025 Proxy Statement.

 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 2025 Proxy Statement.

 Information concerning the Company's policy regarding incentive-based compensation received by current and former officers in the event of a required accounting restatement is included in Exhibit 97 to this Form 10-K.

 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 2025 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, 2024:

 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
 227,422
 —
 783,025

 Equity Compensation Plans Not Approved by Security Holders
 —
 —
 —

 Total
 227,422
 —
 783,025

 (a) Includes the following as of December 31, 2024: (i) 32,674 securities representing the performance shares (including accrued dividends) granted under the executive long-term incentive compensation plan that vested but were not paid as of December 31, 2024; (ii) 108,927 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 (iii) 85,821 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 2025 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) 494,870 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) 255,431 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) 32,724 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 2025 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 2025 Proxy Statement.

 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

 Consolidated Balance Sheet as of December 31, 2024 and 2023

 For the Years Ended December 31, 2024, 2023 and 2022

 Consolidated Statement of Income

 Consolidated Statement of Comprehensive Income

 Consolidated Statement of Cash Flows

 Consolidated Statement of Equity

 Notes to Consolidated Financial Statements

 (2)
 Financial Statement Schedules

 Schedule II – ALLETE Valuation and Qualifying Accounts and Reserves

 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.

 *2

 —
 Agreement and Plan of Merger by and among ALLETE, Inc., Alloy Parent LLC and Alloy Merger Sub LLC, dated as of May 5, 2024 (filed as Exhibit 2.1 to the May 6, 2024, Form 8-K, File No. 1-3548).**

 *3(a)1

 —
 Articles of Incorporation, amended and restated as of May 8, 2001 (filed as Exhibit 3(b) to the March 31, 2001, Form 10 Q, File No. 1-3548).

 *3(a)2

 —
 Amendment to Articles of Incorporation, dated as of September 20, 2004 (filed as Exhibit 3 to the September 21, 2004, Form 8-K, File No. 1-3548).

 *3(a)3

 —
 Amendment to Articles of Incorporation, dated as of May 12, 2009 (filed as Exhibit 3 to the June 30, 2009, Form 10-Q, File No. 1-3548).

 *3(a)4

 —
 Amendment to Articles of Incorporation, dated as of May 11, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548).

 *3(a)5

 —
 Amendment to Certificate of Assumed Name, filed with the Minnesota Secretary of State on May 8, 2001 (filed as Exhibit 3(a) to the March 31, 2001, Form 10-Q, File No. 1-3548).

 *3(b)

 Bylaws, as amended effective April 13, 2020 (filed as Exhibit 3 to the April 14, 2020, Form 8-K, File No. 1-3548).

 *4(a)1
 —
 Mortgage and Deed of Trust, dated as of September 1, 1945, between Minnesota Power & Light Company (now ALLETE) and The Bank of New York Mellon (formerly Irving Trust Company) and Sherma Thomas (successor to Richard H. West), Trustees (filed as Exhibit 7(c), File No. 2-5865).

 *4(a)2
 —
 Supplemental Indentures to ALLETE's Mortgage and Deed of Trust:

 Number
 Dated as of
 Reference File
 Exhibit

 First
 March 1, 1949
 2-7826
 7(b)

 Second
 July 1, 1951
 2-9036
 7(c)

 Third
 March 1, 1957
 2-13075
 2(c)

 Fourth
 January 1, 1968
 2-27794
 2(c)

 Fifth
 April 1, 1971
 2-39537
 2(c)

 Sixth
 August 1, 1975
 2-54116
 2(c)

 Seventh
 September 1, 1976
 2-57014
 2(c)

 Eighth
 September 1, 1977
 2-59690
 2(c)

 Ninth
 April 1, 1978
 2-60866
 2(c)

 Tenth
 August 1, 1978
 2-62852
 2(d)2

 Eleventh
 December 1, 1982
 2-56649
 4(a)3

 Twelfth
 April 1, 1987
 33-30224
 4(a)3

 Thirteenth
 March 1, 1992
 33-47438
 4(b)

 Fourteenth
 June 1, 1992
 33-55240
 4(b)

 Fifteenth
 July 1, 1992
 33-55240
 4(c)

 Sixteenth
 July 1, 1992
 33-55240
 4(d)

 Seventeenth
 February 1, 1993
 33-50143
 4(b)

 Eighteenth
 July 1, 1993
 33-50143
 4(c)

 Nineteenth

 February 1, 1997

 1-3548 (1996 Form 10-K)

 4(a)3

 Twentieth

 November 1, 1997

 1-3548 (1997 Form 10-K)

 4(a)3

 Twenty-first

 October 1, 2000

 333-54330

 4(c)3

 Twenty-second

 July 1, 2003

 1-3548 (June 30, 2003, Form 10-Q)

 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)

 Twenty-fifth

 December 1, 2005

 1-3548 (March 31, 2006, Form 10-Q)

 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)

 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)

 Thirty-second

 August 1, 2010

 1-3548 (Sept. 30, 2010, Form 10-Q)

 Thirty-third

 July 1, 2012

 1-3548 (July 2, 2012, Form 8-K)

 Thirty-fourth

 April 1, 2013

 1-3548 (April 2, 2013, Form 8-K)

 Thirty-fifth

 March 1, 2014

 1-3548 (March 31, 2014, Form 10-Q)

 Thirty-sixth

 June 1, 2014

 1-3548 (June 30, 2014, Form 10-Q)

 Thirty-seventh

 September 1, 2014

 1-3548 (Sept. 30, 2014, Form 10-Q)

 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)

 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)

 Forty-third

 August 1, 2022

 1-3548 (Sept. 30, 2022, Form 10-Q)

 Forty-fourth

 April 1, 2023

 1-3548 (June 30, 2023, Form 10-Q)

 Forty-fifth

 April 1, 2024

 1-3548 (March 31, 2024, Form 10-Q)

 *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)

 Fourteenth

 June 14, 2021

 1-3548 (June 30, 2021, Form 10-Q)

 4(a)

 Fifteenth

 June 14, 2021

 1-3548 (June 30, 2021, Form 10-Q)

 4(b)

 *4(c)

 —
 Note Purchase and Guarantee Agreement dated as of November 5, 2015, among Armenia Mountain Wind LLC, AMW I Holding, LLC and the purchasers named therein (filed as Exhibit 4 to the November 12, 2015, Form 8-K, File No. 1-3548).

 *4(d)

 —
 Note Purchase Agreement, dated December 8, 2016, between ALLETE and Hartford Investment Management Company, Northwestern Mutual Investment Management Company, The Northwestern Mutual Life Insurance Company and Nationwide Life insurance Company (filed as Exhibit 4 to the December 12, 2016, Form 8-K, File No. 1-3548).

 *4(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)

 —
 Note Purchase Agreement, dated June 27, 2024, between ALLETE and the purchasers named therein. (filed as Exhibit 4 to the June 30, 2024, Form 10-Q, File No. 1-3548).

 *4(g)

 —
 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(b)4

 —
 Third Amendment to Credit Agreement dated as of October 17, 2023, among ALLETE, as Borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent. (filed as Exhibit 10 to the Sept. 30, 2023, Form 10-Q, File No. 1-3548).

 10(b)5

 —
 Fourth Amendment to Credit Agreement dated as of June 4, 2024, among ALLETE, as Borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.

 *10(c)1

 —
 Financing Agreement between Collier County Industrial Development Authority and ALLETE dated as of July 1, 2006 (filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File No. 1-3548).

 *10(c)2

 —
 Amended and Restated Letter of Credit Agreement, dated as of June 3, 2011, among ALLETE, the participating banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (filed as Exhibit 10(b) to the June 30, 2011, Form 10-Q, File No. 1-3548).

 *10(c)3

 —
 First Amendment to Amended and Restated Letter of Credit Agreement, dated as of June 1, 2013, between ALLETE and Wells Fargo Bank, National Association, as Issuing Bank, Administrative Agent and Sole Participating Bank (filed as Exhibit 10(b) to the June 30, 2013, Form 10-Q, File No. 1-3548).

 *10(d)

 —
 Agreement dated December 16, 2005, among ALLETE, Wisconsin Public Service Corporation and WPS Investments, LLC (filed as Exhibit 10(g) to the 2009 Form 10-K, File No. 1-3548).

 *+10(e)1

 —
 ALLETE Executive Annual Incentive Plan, as amended and restated, effective January 1, 2011 (filed as Exhibit 10(h)1 to the 2010 Form 10-K, File No. 1-3548).

 *+10(e)2

 —
 ALLETE Executive Annual Incentive Plan Form of Award Effective 2021 (filed as Exhibit 10(e)8 to the 2020 Form 10-K, File No. 1-3548).

 *+10(e)3

 —
 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)4

 —
 ALLETE Executive Annual Incentive Plan Form of Award Effective 2023 (filed as Exhibit 10(e)8 to the 2022 Form 10-K, File No. 1-3548).

 *+10(e)5

 —
 ALLETE Executive Annual Incentive Plan Form of Award ALLETE Clean Energy Effective 2023 (filed as Exhibit 10(e)9 to the 2022 Form 10-K, File No. 1-3548).

 *+10(e)6

 —
 ALLETE Executive Annual Incentive Plan, as amended and restated, effective December 21, 2023 (filed as Exhibit 10(e)7 to the 2023 Form 10-K, File No. 1-3548).

 *+10(e)7

 —
 ALLETE Executive Annual Incentive Plan Form of Award Effective 2024 (filed as Exhibit 10(e)8 to the 2023 Form 10-K, File No. 1-3548).

 *+10(e)8

 —
 ALLETE Executive Annual Incentive Plan Form of Award ALLETE Clean Energy Effective 2024 (filed as Exhibit 10(e)9 to the 2023 Form 10-K, File No. 1-3548).

 +10(e)9

 —
 ALLETE Executive Annual Incentive Plan Form of Award Effective 2025.

 +10(e)10

 —
 ALLETE Executive Annual Incentive Plan Form of Award ALLETE Clean Energy Effective 2025.

 *+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, 2021 (filed as Exhibit 10(f)5 to the 2021 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 October 27, 2023 (filed as Exhibit 10(f)4 to the 2023 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 2019 (filed as Exhibit 10(i)10 to the 2018 Form 10-K, File No. 1-3548).

 *+10(h)3

 —
 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)4

 —
 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)5

 —
 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)6

 —
 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)7

 —
 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)8

 —
 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)9

 —
 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)10

 —
 ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective April 13, 2022. (filed as Exhibit 10.1 to the September 30, 2024, Form 10-Q, File No. 1-3548).

 *+10(h)11

 —
 Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2023 (filed as Exhibit 10(h)16 to the 2022 Form 10-K, File No. 1-3548).

 *+10(h)12

 —
 Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2023 (filed as Exhibit 10(h)17 to the 2022 Form 10-K, File No. 1-3548).

 *+10(h)13

 —
 Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2024 (filed as Exhibit 10(h)15 to the 2023 Form 10-K, File No. 1-3548).

 *+10(h)14

 —
 Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2024 (filed as Exhibit 10(h)16 to the 2023 Form 10-K, File No. 1-3548).

 +10(h)15

 —
 Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2025.

 +10(h)16

 —
 Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2025.

 *+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 (filed as Exhibit 10(j)6 to the 2022 Form 10-K, File No. 1-3548).

 *+10(k)1

 —
 Minnesota Power (now ALLETE) 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).

 *+10(n)

 —
 Extraordinary Compensation Award and Opportunity Effective September 25, 2023 (filed as Exhibit 10.2 to the September 30, 2024, Form 10-Q, File No. 1-3548).

 *+10(o)1

 —
 ALLETE and Affiliated Companies Change in Control Severance Plan, as amended and restated, effective April 23, 2018 (filed as Exhibit 10(c) to the March 31, 2018, Form 10-Q, File No. 1-3548).

 *+10(o)2

 —
 ALLETE and Affiliated Companies Change in Control Severance Plan, as amended and restated, effective October 27, 2023 (filed as Exhibit 10(n)2 to the 2023 Form 10-K, File No. 1-3548).

 —
 Insider Trading Policies and Procedures.

 —
 Subsidiaries of the Registrant.

 —
 Consent of Independent Registered Public Accounting Firm.

 31(a)

 —
 Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 31(b)

 —
 Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 —
 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.

 —
 Mine Safety.

 —
 Policy Relating to Recovery of Erroneously Awarded Compensation.

 —
 ALLETE News Release dated February 13, 2025, announcing earnings for the year ended December 31, 2024. (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
 —

 101.SCH
 —

 101.CAL
 —

 101.DEF
 —

 101.LAB
 —

 101.PRE
 —

 —

 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.

 **
 Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedules will be furnished supplementally to the SEC upon request provided, however, that the parties may request confidential treatment pursuant to Rule 24b-2 of the Exchange Act for any document so furnished.

 +
 Management contract or compensatory plan or arrangement pursuant to Item 15(b).

 Item 16. Form 10-K Summary

 None.

 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:
 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

 Bethany M. Owen

 (Principal Executive Officer) and Director

 /s/ Steven W. Morris

 Senior Vice President and Chief Financial Officer

 Steven W. Morris

 (Principal Financial Officer and Principal Accounting Officer)

 Signatures (Continued)
 Signature

 Title

 Date

 /s/ George G. Goldfarb

 George G. Goldfarb

 /s/ James J. Hoolihan

 James J. Hoolihan

 /s/ Madeleine W. Ludlow

 Madeleine W. Ludlow

 /s/ Charles R. Matthews

 Charles R. Matthews

 /s/ Susan K. Nestegard

 Susan K. Nestegard

 /s/ Douglas C. Neve

 Douglas C. Neve

 /s/ Barbara A. Nick

 Barbara A. Nick

 /s/ Robert P. Powers

 Robert P. Powers

 /s/ Charlene A. Thomas

 Charlene A. Thomas

 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, 2024 and 2023, 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, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
 Basis for Opinions
 The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company's consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
 Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 Definition and Limitations of Internal Control over Financial Reporting
 A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 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, 2024, there was $373.3 million of regulatory assets and $602.0 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
 We have served as the Company's auditor since 1963.

 CONSOLIDATED FINANCIAL STATEMENTS

 ALLETE Consolidated Balance Sheet

 2024
 2023

 Assets

 Current Assets

 $ 32.8
 $ 71.9

 Accounts Receivable (Less Allowance of $ 1.7 and $ 1.6)

 148.1
 137.2

 Inventories – Net
 154.6
 175.4

 Prepayments and Other
 99.7
 83.6

 Total Current Assets
 435.2
 468.1

 Property, Plant and Equipment – Net
 5,181.5
 5,013.4

 Regulatory Assets
 371.7
 425.4

 Equity Investments
 340.1
 331.2

 Goodwill and Intangible Assets – Net
 155.3
 155.4

 Other Non-Current Assets
 270.5
 262.9

 Total Assets
 $ 6,754.3
 $ 6,656.4

 Liabilities, Redeemable Non-Controlling Interest and Equity

 Liabilities

 Accounts Payable
 $ 113.6
 $ 102.2

 Accrued Taxes
 54.6
 51.0

 Accrued Interest
 23.4
 21.1

 Long-Term Debt Due Within One Year
 94.7
 111.4

 Other
 117.9
 91.9

 Total Current Liabilities
 404.2
 377.6

 1,704.7
 1,679.9

 Deferred Income Taxes
 253.4
 192.7

 Regulatory Liabilities
 570.5
 574.0

 Defined Benefit Pension and Other Postretirement Benefit Plans
 118.2
 160.8

 Other Non-Current Liabilities
 312.8
 264.3

 Total Liabilities
 3,363.8
 3,249.3

 Commitments, Guarantees and Contingencies (Note 9)

 Redeemable Non-Controlling Interest
 0.4
 0.5

 Equity

 ALLETE Equity

 Common Stock Without Par Value, 80.0 Shares Authorized, 57.9 and 57.6 Shares Issued and Outstanding

 1,823.2
 1,803.7

 Accumulated Other Comprehensive Loss
 ( 18.1)
 ( 20.5)

 Retained Earnings
 1,042.9
 1,026.4

 Total ALLETE Equity
 2,848.0
 2,809.6

 Non-Controlling Interest in Subsidiaries
 542.1
 597.0

 Total Equity
 3,390.1
 3,406.6

 Total Liabilities, Redeemable Non-Controlling Interest and Equity
 $ 6,754.3
 $ 6,656.4

 ALLETE Consolidated Statement of Income

 2024
 2023
 2022

 Millions Except Per Share Amounts

 Contracts with Customers – Utility
 $ 1,242.7
 $ 1,238.3
 $ 1,259.3

 282.1
 636.4
 303.8

 Other – Non-utility
 5.0
 5.1
 7.6

 1,529.8
 1,879.8
 1,570.7

 Operating Expenses

 477.6
 482.9
 545.5

 64.6
 88.2
 76.7

 129.2
 473.5
 182.8

 361.4
 345.3
 318.9

 271.5
 251.8
 242.2

 65.4
 57.2
 70.4

 Total Operating Expenses
 1,369.7
 1,698.9
 1,436.5

 160.1
 180.9
 134.2

 Other Income (Expense)

 ( 81.7)
 ( 80.8)
 ( 75.2)

 25.0
 21.7
 18.7

 Other
 23.0
 85.0
 22.4

 Total Other Income (Expense)
 ( 33.7)
 25.9
 ( 34.1)

 Income Before Non-Controlling Interest and Income Taxes
 126.4
 206.8
 100.1

 Income Tax Expense (Benefit)
 4.7
 27.9
 ( 31.2)

 Net Income
 121.7
 178.9
 131.3

 Net Loss Attributable to Non-Controlling Interest
 ( 57.6)
 ( 68.2)
 ( 58.0)

 Average Shares of Common Stock

 Basic
 57.7
 57.3
 55.9

 57.8
 57.4
 56.0

 Basic Earnings Per Share of Common Stock
 $ 3.11
 $ 4.31
 $ 3.38

 Diluted Earnings Per Share of Common Stock
 $ 3.10
 $ 4.30
 $ 3.38

 ALLETE Consolidated Statement of Comprehensive Income

 2024
 2023
 2022

 Net Income
 $ 121.7
 $ 178.9
 $ 131.3

 Other Comprehensive Income (Loss)

 Unrealized Gain (Loss) on Securities

 Net of Income Tax Expense (Benefit) of $ —, $ 0.1 and $( 0.2)

 0.1
 0.3
 ( 0.4)

 Defined Benefit Pension and Other Postretirement Benefit Plans

 Net of Income Tax Expense (Benefit) of $( 0.1), $ 2.4 and $( 0.1)

 2.3
 3.6
 ( 0.2)

 Total Other Comprehensive Income (Loss)
 2.4
 3.9
 ( 0.6)

 Total Comprehensive Income
 124.1
 182.8
 130.7

 Net Loss Attributable to Non-Controlling Interest
 ( 57.6)
 ( 68.2)
 ( 58.0)

 Total Comprehensive Income Attributable to ALLETE
 $ 181.7
 $ 251.0
 $ 188.7

 ALLETE Consolidated Statement of Cash Flows

 2024
 2023
 2022

 Operating Activities

 Net Income
 $ 121.7
 $ 178.9
 $ 131.3

 Adjustments to Reconcile Net Income to Cash provided by Operating Activities:

 AFUDC – Equity
 ( 5.0)
 ( 3.6)
 ( 2.7)

 Income from Equity Investments – Net of Dividends
 ( 1.8)
 1.0
 2.4

 (Gain) / Loss on Investments and Property, Plant and Equipment
 —
 —
 1.2

 Depreciation Expense
 271.3
 251.7
 242.0

 Amortization of PSAs
 ( 5.0)
 ( 5.2)
 ( 7.6)

 Amortization of Other Intangible Assets and Other Assets
 6.9
 7.1
 8.3

 Deferred Income Tax Expense (Benefit)
 ( 15.8)
 17.6
 ( 38.5)

 Share-Based and ESOP Compensation Expense
 6.6
 7.3
 4.9

 Defined Benefit Pension and Other Postretirement Plan Expense (Benefit)
 ( 13.8)
 ( 6.1)
 ( 3.0)

 Bad Debt Expense
 1.4
 1.3
 1.9

 Fuel Adjustment Clause
 0.6
 44.0
 15.1

 Provision (Payments) for Interim Rate Refund
 23.0
 ( 18.4)
 18.4

 Changes in Operating Assets and Liabilities

 Accounts Receivable
 ( 13.1)
 1.8
 ( 14.0)

 Inventories
 7.5
 277.1
 ( 256.1)

 Prepayments and Other
 ( 10.5)
 ( 7.9)
 ( 21.5)

 Accounts Payable
 ( 2.7)
 ( 4.0)
 ( 1.3)

 Other Current Liabilities
 0.9
 ( 157.6)
 116.2

 Renewable Tax Credit Sales
 61.1
 —
 —

 Cash Contributions to Defined Benefit Pension Plans
 ( 25.0)
 ( 17.3)
 —

 Changes in Regulatory and Other Non-Current Assets
 42.2
 15.6
 24.1

 Changes in Regulatory and Other Non-Current Liabilities
 6.6
 2.0
 0.2

 Cash provided by Operating Activities
 457.1
 585.3
 221.3

 Investing Activities

 Proceeds from Sale of Available-for-sale Securities
 2.0
 1.0
 2.2

 Payments for Purchase of Available-for-sale Securities
 ( 2.4)
 ( 1.2)
 ( 2.4)

 Acquisitions of Subsidiaries – Net of Cash and Restricted Cash Acquired
 —
 —
 ( 155.0)

 Payments for Equity Investments
 ( 5.8)
 ( 8.2)
 ( 5.9)

 Additions to Property, Plant and Equipment
 ( 354.9)
 ( 271.2)
 ( 220.5)

 Other Investing Activities
 20.4
 ( 4.0)
 ( 2.4)

 Cash used in Investing Activities
 ( 340.7)
 ( 283.6)
 ( 384.0)

 Financing Activities

 Proceeds from Issuance of Common Stock
 12.9
 14.9
 248.0

 Equity Issuance Costs
 —
 —
 ( 8.1)

 Proceeds from Issuance of Short-Term and Long-Term Debt
 658.0
 437.0
 785.4

 Repayments of Short-Term and Long-Term Debt
 ( 649.4)
 ( 566.7)
 ( 877.0)

 Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs
 4.1
 17.8
 155.7

 Distributions to Non-Controlling Interest
 ( 1.5)
 ( 8.5)
 ( 1.7)

 Dividends on Common Stock
 ( 162.8)
 ( 155.5)
 ( 145.9)

 Other Financing Activities
 ( 1.9)
 ( 1.5)
 ( 1.2)

 Cash provided (used in) by Financing Activities
 ( 140.6)
 ( 262.5)
 155.2

 Change in Cash, Cash Equivalents and Restricted Cash
 ( 24.2)
 39.2
 ( 7.5)

 Cash, Cash Equivalents and Restricted Cash at Beginning of Period
 79.4
 40.2
 47.7

 Cash, Cash Equivalents and Restricted Cash at End of Period
 $ 55.2
 $ 79.4
 $ 40.2

 ALLETE Consolidated Statement of Equity

 2024
 2023
 2022

 Millions Except Per Share Amounts

 Equity

 Common Stock

 $ 1,803.7
 $ 1,781.5
 $ 1,536.7

 Common Stock Issued
 19.5
 22.2
 244.8

 Balance, End of Period
 1,823.2
 1,803.7
 1,781.5

 Accumulated Other Comprehensive Loss

 ( 20.5)
 ( 24.4)
 ( 23.8)

 Other Comprehensive Income – Net of Income Taxes

 Unrealized Gain (Loss) on Debt Securities
 0.1
 0.3
 ( 0.4)

 Defined Benefit Pension and Other Postretirement Plans
 2.3
 3.6
 ( 0.2)

 Balance, End of Period
 ( 18.1)
 ( 20.5)
 ( 24.4)

 Retained Earnings

 1,026.4
 934.8
 891.4

 179.3
 247.1
 189.3

 Common Stock Dividends
 ( 162.8)
 ( 155.5)
 ( 145.9)

 Balance, End of Period
 1,042.9
 1,026.4
 934.8

 Non-Controlling Interest in Subsidiaries

 597.0
 656.4
 533.2

 Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs
 1.3
 9.9
 182.9

 Net Loss Attributable to Non-Controlling Interest
 ( 55.0)
 ( 60.8)
 ( 58.0)

 Distributions to Non-Controlling Interest
 ( 1.2)
 ( 8.5)
 ( 1.7)

 Balance, End of Period
 542.1
 597.0
 656.4

 Total Equity
 $ 3,390.1
 $ 3,406.6
 $ 3,348.3

 Redeemable Non-Controlling Interest

 $ 0.5
 —
 —

 Proceeds from Non-Controlling Interest in Subsidiaries
 2.8
 $ 7.9
 —

 Net Loss Attributable to Non-Controlling Interest
 ( 2.6)
 ( 7.4)
 —

 Distributions to Non-Controlling Interest
 ( 0.3)
 —
 —

 Total Redeemable Non-Controlling Interest
 $ 0.4
 $ 0.5
 —

 Dividends Per Share of Common Stock
 $ 2.82
 $ 2.71
 $ 2.60

 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, certain New Energy Equity 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, operates, or has developed 1,600 MW of wind energy generation in five major energy markets and eight states across the U.S. 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.

 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. (See Note 3. Jointly-Owned Facilities and Assets.)

 BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2024, 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, 2024, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet are primarily related to funds held in escrow for the purchase of land. As of December 31, 2024, and 2023, restricted cash amounts included in Prepayments and Other also include deposits required under a tax equity financing agreement and 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 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

 2024
 2023
 2022

 $ 32.8
 $ 71.9
 $ 36.4

 Restricted Cash included in Prepayments and Other
 19.9
 5.1
 1.5

 Restricted Cash included in Other Non-Current Assets
 2.5
 2.4
 2.3

 Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows
 $ 55.2
 $ 79.4
 $ 40.2

 Supplemental Statement of Cash Flow Information.
 Consolidated Statement of Cash Flows

 2024
 2023
 2022

 Cash Paid During the Period for Interest – Net of Amounts Capitalized
 $ 75.1
 $ 80.5
 $ 72.8

 Cash Paid for Income Taxes
 $ 19.1
 $ 19.5
 $ 6.0

 Noncash Investing and Financing Activities

 Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment
 $ 15.5
 $ 2.2
 $( 9.6)

 Reclassification of Property, Plant and Equipment to Inventory (a)

 —
 —
 $ 99.7

 Capitalized Asset Retirement Costs (b)

 $ 55.0
 $ 5.8
 $ 11.8

 AFUDC–Equity
 $ 5.0
 $ 3.6
 $ 2.7

 (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)Capitalized asset retirement costs in 2024 reflect the impact of estimated compliance costs related to the EPA's CCR Legacy Impoundment Rule finalized in May 2024. (See Note 9. Commitments, Guarantees and Contingencies.)

 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

 2024
 2023

 Trade Accounts Receivable

 Billed
 $ 115.9
 $ 106.8

 Unbilled
 27.2
 23.8

 Less: Allowance for Doubtful Accounts
 1.7
 1.6

 Total Trade Accounts Receivable
 141.4
 129.0

 Income Taxes Receivable
 6.7
 8.2

 Total Accounts Receivable
 $ 148.1
 $ 137.2

 Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $ 13.3 million as of December 31, 2024 ($ 11.2 million as of December 31, 2023). 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 2024, accounted for 33 percent of Regulated Operations operating revenue and 27 percent of consolidated operating revenue in 2024 ( 32 percent of Regulated Operations operating revenue and 21 percent of consolidated operating revenue in 2023 and 32 percent of Regulated Operations operating revenue and 26 percent of consolidated operating revenue in 2022).

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

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

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

 Inventories – Net

 2024
 2023

 Fuel (a)

 $ 22.5
 $ 27.2

 Materials and Supplies
 107.6
 115.7

 Renewable Energy Facilities Under Development (b)

 24.5
 32.5

 Total Inventories – Net
 $ 154.6
 $ 175.4

 (a) Fuel consists primarily of coal inventory at Minnesota Power.
 (b) Renewable Energy Facilities Under Development consists primarily of project costs related to renewable energy development projects at New Energy.

 Prepayments and Other Current Assets. Prepayments and Other on the Consolidated Balance Sheet included $ 32.4 million of costs in excess of billings at New Energy as of December 31, 2024 ($ 21.5 million as of December 31, 2023).

 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, except New Energy, are recognized when they are retired or otherwise disposed. When property, plant and equipment in our Regulated Operations and ALLETE Clean Energy segments as well as at New Energy are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for composite 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 $ 220 million and $ 395 million, respectively, as of December 31, 2024. (See Note 4. Regulatory Matters.) Minnesota Power also retired Taconite Harbor in the first quarter of 2023 consistent with its latest IRP. As part of the 2022 general retail rate case, the MPUC allowed recovery of the remaining book value of Taconite Harbor through 2026. We do not expect to record any impairment charge as a result of these operating changes at Taconite Harbor and Boswell. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives.

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

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

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

 In 2023 and 2022 there were triggering events identified for our property, plant, and equipment at certain ALLETE Clean Energy wind energy facilities. 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 2023 or 2022. In 2024, there were no triggering events identified for our property, plant, and equipment at ALLETE Clean Energy.

 Government Grants. We recognize government grants when there is reasonable assurance that the Company will comply with the conditions attached to the grant and that the grant will be received. Grants whose primary condition is the purchase, construction, or acquisition of a long-lived asset are considered asset-based grants and are recognized as a reduction to such asset's cost basis, which reduces future depreciation. Cash inflows from asset-based grants are considered cash flows provided by investing activities. Other grants not related to long-lived assets are considered income-based grants, which are recognized as a reduction to the related cost of activities that generated the benefit are presented. Cash inflows from grants related to income are considered cash flows provided by operating activities.

 In the third quarter of 2024, Minnesota Power received $ 14.9 million in state funding related to its HVDC Transmission System Project as part of an energy and climate budget bill passed by the Minnesota Legislature in 2023. This was considered an asset-based grant and resulted in the reduction to cost basis for the related assets, and it is subject to regulatory obligations with the MPUC.

 There were no benefits recognized from income-based government grants in our consolidated statement of income in 2022, 2023 or 2024.

 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 and transmission congestion cost risk related to sales to electric customers. We have determined that either these agreements are immaterial to the financial statements, are not derivatives, or, if they are derivatives, these 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 2024, 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 2024 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 12.5 percent, cash flow forecasts through 2033, gross margins, and a terminal growth rate of 3.5 percent.

 Other Non-Current Assets

 2024
 2023

 Contract Assets (a)

 $ 15.9
 $ 18.5

 ALLETE Properties
 10.3
 10.8

 Restricted Cash
 2.5
 2.4

 Other Postretirement Benefit Plans
 107.6
 106.3

 Other
 134.2
 124.9

 Total Other Non-Current Assets
 $ 270.5
 $ 262.9

 (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

 2024
 2023

 Customer Deposits
 $ 7.8
 $ 7.4

 PSAs
 5.9
 6.0

 Provision for Interim Rate Refund
 23.0
 —

 Manufactured Gas Plant (a)

 0.1
 0.8

 Other
 81.1
 77.7

 Total Other Current Liabilities
 $ 117.9
 $ 91.9

 (a) 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.)

 Other Non-Current Liabilities

 2024
 2023

 Asset Retirement Obligation (a)(b)

 $ 261.3
 $ 202.9

 PSAs
 15.1
 20.9

 Other
 36.4
 40.5

 Total Other Non-Current Liabilities
 $ 312.8
 $ 264.3

 (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 $ 42.3 million in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2024 ($ 37.2 million as of December 31, 2023).
 (b) The increase in Asset Retirement Obligation in 2024 reflects the impact of estimated compliance costs related to the EPA's CCR Legacy Impoundment Rule finalized in May 2024. (See Note 9. Commitments, Guarantees and Contingencies.)

 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 and finance leases are included in Other Non-Current Assets, Other Current Liabilities and Other Non-Current Liabilities, respectively, in our Consolidated Balance Sheet.

 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 and finance 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 and finance lease right-of-use assets 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 are recognized on a straight-line basis over the lease term for operating leases. Finance leases recognize interest expense using the interest expense method over the lease term and amortization expense on a straight-line basis over the shorter of the useful life of the asset or the lease term, unless a buy out option is reasonably certain to be exercised, for which we then amortize on a straight-line basis over the useful life of the asset. 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 drag line 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. We have one finance lease for heavy equipment which includes a purchase option we are reasonably certain to exercise when the lease terminates.

 Leases (Continued)

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

 As December 31
 2024
 2023

 Operating Lease Cost
 $ 5.4
 $ 5.0

 Finance Lease Cost
 $ 0.3
 $ 0.1

 Other Information:

 Operating Cash Flows From Operating Leases
 $ 5.4
 $ 5.0

 Financing Cash Flows From Finance Leases
 $ 0.4
 $ 0.2

 Additional information related to leases were as follows:
 2024
 2023

 Balance Sheet Information Related to Leases:

 Operating Lease Other Non-Current Assets
 $ 9.1
 $ 10.7

 Finance Lease Other Non-Current Assets
 1.9
 2.1

 Total Lease Right-of-use Assets
 $ 11.0
 $ 12.8

 Operating Lease Other Current Liabilities
 $ 3.2
 $ 3.0

 Finance Lease Other Current Liabilities
 0.4
 0.4

 Operating Lease Other Non-Current Liabilities
 6.0
 7.7

 Finance Lease Other Non-Current Liabilities
 1.3
 1.6

 Total Lease Liabilities
 $ 10.9
 $ 12.7

 Income Statement Information Related to Leases:

 Operating Lease Rent Expense
 $ 5.4
 $ 5.0

 Finance Lease Interest Expense
 0.1
 —

 Finance Lease Amortization Expense
 0.2
 0.1

 Total Operating and Finance Lease Expenses
 $ 5.7
 $ 5.1

 Weighted Average Remaining Lease Term (Years):

 Operating Leases - Vehicles and Equipment

 Operating Leases - Land and Other

 Finance Leases - Vehicles and Equipment

 Weighted Average Discount Rate:

 Operating Leases - Vehicles and Equipment
 4.0
 %
 4.0
 %

 Operating Leases - Land and Other
 5.9
 %
 5.0
 %

 Finance Leases - Vehicles and Equipment
 5.4
 %
 5.4
 %

 Leases (Continued)

 Maturities of operating and finance lease liabilities as of December 31, 2024, were as follows:

 Operating
 Finance

 2025
 $ 3.4
 $ 0.4

 2026
 3.3
 0.4

 2027
 4.2
 0.5

 2028
 0.3
 0.6

 2029
 0.1
 —

 Thereafter
 3.4
 —

 Total Lease Payments Due
 14.7
 1.9

 Less: Imputed Interest
 5.5
 0.2

 Total Lease Obligations
 9.2
 1.7

 Less: Current Lease Obligations
 3.2
 0.4

 Total Long-term Lease Obligations
 $ 6.0
 $ 1.3

 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.

 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 56 percent of total regulated utility kWh sales for the year ended December 31, 2024. Within industrial revenue, Minnesota Power had eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load as of December 31, 2024. 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 2028 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 $ 60 million per annum through 2028 and approximately $ 10 million in 2029, 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.

 ECO Financial incentives reflects certain revenue that is a result of the achievement of certain objectives for our ECO 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. ECO financial incentives are recognized in the period in which the MPUC approves the filing, which is typically mid-year.

 Revenue (Continued)

 Non-utility

 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 2027 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.

 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 days 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.

 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, 2024, we have $ 15.9 million of assets recognized for costs incurred to obtain contracts with our customers ($ 18.5 million as of December 31, 2023). 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, 2024 ($ 2.4 million for the year ended December 31, 2023).

 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 and solar 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 or defined time period is met, 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 and Redeemable Non-Controlling Interest. Non-controlling interest in subsidiaries and redeemable non-controlling interest represent the portion of equity ownership, net income (loss), and comprehensive income (loss) in subsidiaries that is not attributable to equity holders of ALLETE. Non-controlling Interest in Subsidiaries as of and for the years ended December 31, 2024 and 2023, are 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. Redeemable Non-Controlling Interest as of and for the year ended December 31, 2024, is related to a tax equity financing entered into in the fourth quarter of 2023 for certain New Energy solar energy facilities totaling 14 MW. This tax equity financing is classified as redeemable non-controlling interest as the redemption price and date are fixed and determinable.

 For those wind and solar 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 and solar 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 as either Non-Controlling Interest in Subsidiaries or Redeemable Non-Controlling Interest.

 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 and redeemable non-controlling interest on the Consolidated Balance Sheet at the start and end of each reporting period, after taking into account any capital transactions between the projects and the third-party investors.

 Factors used in the HLBV calculation include GAAP income, taxable income (loss), tax attributes such as accelerated depreciation, investment tax credits 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

 2024
 2023
 2022

 Pension and Other Postretirement Benefit Plan Non-Service Credit (a)

 $ 13.6
 $ 8.9
 $ 9.8

 Interest and Investment Income (b)

 4.0
 10.3
 —

 AFUDC - Equity
 5.0
 3.6
 2.7

 Gain on Land Sales
 0.1
 0.2
 —

 PSA Liability (c)

 —
 —
 10.2

 Gain on Arbitration Award (d)

 —
 58.4
 —

 Other Income (Expense)
 0.3
 3.6
 ( 0.3)

 Total Other Income (Expense) - Other
 $ 23.0
 $ 85.0
 $ 22.4

 (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)Interest and Investment Income for the year ended December 31, 2023, reflects $ 5.1 million of interest income related to interest awarded as part of an arbitration ruling involving a subsidiary of ALLETE Clean Energy. (See Note 9. Commitments, Guarantees and Contingencies.)
 (c)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 that was recorded in Cost of Sales - Non-Utility on the Consolidated Statement of Income.
 (d)This reflects a gain recognized for the favorable outcome of an arbitration ruling involving a subsidiary of ALLETE Clean Energy. (See Note 9. Commitments, Guarantees and Contingencies.)

 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.

 New Accounting Standards.

 Improvements to Reportable Segment Disclosures. In November 2023, the FASB issued Accounting Standards Update 2023-07, Improvements to Reportable Segment Disclosures (ASU 2023-07). ASU 2023-07 requires that an entity provide enhanced disclosures about significant segment expenses that are regularly provided to the chief operating decision maker, among other disclosures. ASU 2023-07 is effective for annual periods beginning after December 15, 2023, and this Form 10-K includes the required disclosures. We expect to provide enhanced disclosures for quarterly periods beginning in 2025.

 Improvements to Income Tax Disclosures. In December 2023, the FASB issued Accounting Standards Update 2023-09, Improvements to Income Tax Disclosures (ASU 2023-09). ASU 2023-09 was issued to enhance the transparency and decision usefulness of income tax disclosures by disclosing specific categories in the rate reconciliation as well as providing additional information for reconciling items above a threshold. It also requires disclosure about certain income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. We do not anticipate ASU 2023-09 having a material effect on the presentation of ALLETE's consolidated financial statements.

 Disaggregation of Income Statement Expenses. In November 2024, the FASB issued Accounting Standards Update 2024-03, Disaggregation of Income Statement Expenses (ASU 2024-03). ASU 2024-03 was issued to improve expense disclosures by providing more detailed information about the types of expenses in commonly presented expense captions. ASU 2024-03 is effective for annual periods beginning after December 25, 2026, and quarterly periods beginning after December 15, 2027. We do not anticipate ASU 2024-03 having a material effect on the presentation of ALLETE's consolidated financial statements.

 SEC Climate-related Disclosures Rule. On March 6, 2024, the SEC issued the final rules regarding the enhancement and standardization of climate-related disclosures for investors (Rule). The Rule requires registrants to provide certain climate-related information in their annual reports and registration statements. These requirements include disclosing climate-related risks that materially affect or are reasonably likely to materially affect a registrant's business strategy, results of operations, or financial condition as well as certain disclosures related to greenhouse-gas emissions, and the effects of severe weather events and other natural conditions. The Rule provides that the disclosure requirements will begin phasing in for annual periods beginning in 2025. The Company is evaluating the final rule to determine its impact on the Company's disclosures. The Rule is currently being challenged before the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit Court), and the SEC issued a voluntary stay of the Rule on April 4, 2024, pending judicial review.

 There are no other new accounting standards that we anticipate having a material effect on the presentation of ALLETE's consolidated financial statements.

 NOTE 2. PROPERTY, PLANT AND EQUIPMENT

 Property, Plant and Equipment

 2024
 2023

 Property, Plant and Equipment in Service
 $ 5,387.8
 $ 5,167.2

 Construction Work in Progress
 197.5
 146.7

 Accumulated Depreciation
 ( 2,077.8)
 ( 1,969.4)

 Regulated Operations – Net
 3,507.5
 3,344.5

 Property, Plant and Equipment in Service
 1,605.3
 1,612.8

 Construction Work in Progress
 51.9
 48.9

 Accumulated Depreciation
 ( 272.9)
 ( 229.1)

 ALLETE Clean Energy – Net
 1,384.3
 1,432.6

 Corporate and Other (a)

 Property, Plant and Equipment in Service
 377.4
 355.8

 Construction Work in Progress
 77.5
 27.5

 Accumulated Depreciation
 ( 165.2)
 ( 147.0)

 Corporate and Other – Net
 289.7
 236.3

 Property, Plant and Equipment – Net
 $ 5,181.5
 $ 5,013.4

 (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)

 Generation
 3 to 50

 5 to 35

 Transmission
 50 to 75

 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

 Obligation as of December 31, 2022
 $ 200.4

 Accretion
 10.3

 Liabilities Settled
 ( 10.2)

 Revisions in Estimated Cash Flows
 2.4

 Obligation as of December 31, 2023
 202.9

 Accretion
 13.1

 Liabilities Recognized (a)

 47.7

 Liabilities Settled
 ( 16.0)

 Revisions in Estimated Cash Flows
 13.6

 Obligation as of December 31, 2024
 $ 261.3

 (a) The increase in liabilities recognized in 2024 reflects the impact of estimated compliance costs related to the EPA's CCR Legacy Impoundment Rule finalized in May 2024. (See Note 9. Commitments, Guarantees and Contingencies.)

 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

 As of December 31, 2024

 Boswell Unit 4
 $ 716.2
 $ 396.7
 $ 14.2

 Transmission Assets
 101.1
 26.1
 —
 9.3 - 14.7

 Total
 $ 817.3
 $ 422.8
 $ 14.2

 As of December 31, 2023

 Boswell Unit 4
 $ 725.9
 $ 369.8
 $ 2.8

 Transmission Assets
 101.0
 23.6
 —
 9.3 - 14.7

 Total
 $ 826.9
 $ 393.4
 $ 2.8

 Nemadji Trail Energy Center. 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 upon completion of the facility 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 will be responsible for approximately 20 percent. South Shore Energy's portion of NTEC project costs incurred through December 31, 2024, is approximately $ 10 million.

 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 $ 20.0 million in 2024 ($ 57.0 million in 2023; $ 38.8 million in 2022).

 Minnesota Retail Rates. Minnesota Power's retail base rates through 2022 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. Interim rates were implemented in Minnesota Power's 2022 general rate case beginning in January 2022, and the resolution of Minnesota Power's 2022 general rate case changed the allowed return on equity to 9.65 percent and the equity ratio to 52.50 percent beginning October 1, 2023. (See 2022 Minnesota General Rate Case.) Minnesota Power expects to implement updated rates based on the 2024 MPUC retail rate order in the first quarter of 2025. This order allows for a return on equity 9.78 percent and an equity ratio of 53.00 percent.

 2024 Minnesota General Rate Case. On November 1, 2023, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 12.00 percent for retail customers, net of rider revenue incorporated into base rates. The rate filing sought a return on equity of 10.30 percent and a 53.00 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $ 89 million in additional revenue. In separate orders dated December 19, 2023, the MPUC accepted the filing as complete and approved an annual interim rate increase of approximately $ 64 million, net of rider revenue, beginning January 1, 2024, subject to refund.

 On May 3, 2024, Minnesota Power entered into a settlement agreement with the Minnesota Department of Commerce, Minnesota Office of the Attorney General, Residential Utilities Division, and Large Power Intervenors to settle the retail rate increase request. As part of the settlement agreement, the parties agreed on all issues, including an overall rate increase of $ 33.97 million, net of rider revenue and amounts transferring to the fuel adjustment clause, a return on equity of 9.78 percent, an equity ratio of 53.00 percent, all non-financial items and cost allocation. In an order dated November 25, 2024, the MPUC approved the settlement agreement. Final rates are expected to be implemented in the first quarter of 2025; interim rates will be collected through this period with reserves recorded as necessary. As a result of the settlement, Minnesota Power recorded a reserve for an interim rate refund of $ 23.0 million pre-tax as of December 31, 2024, which is subject to MPUC approval of Minnesota Power's refund calculation.

 2022 Minnesota General Rate Case. In an order dated February 28, 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. In March 2023, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration and clarification of certain decisions in the MPUC's order. The MPUC denied the requests for reconsideration in an order dated May 15, 2023.

 In an order dated September 29, 2023, the MPUC approved Minnesota Power's final rates, which were implemented beginning on October 1, 2023. The MPUC order also approved Minnesota Power's interim rate refund plan. Interim rates were collected through the third quarter of 2023 with reserves recorded as necessary. Minnesota Power recorded a reserve for an interim rate refund of approximately $ 39 million pre-tax as of September 30, 2023 (approximately $ 18 million as of December 31, 2022), which was refunded to customers during the fourth quarter of 2023.

 Minnesota Power appealed with the Minnesota Court of Appeals (Court) specific aspects of the MPUC's February 2023 and May 2023 rate case orders for the ratemaking treatment of Taconite Harbor and Minnesota Power's prepaid pension asset. On September 9, 2024, the Court affirmed the MPUC's Taconite Harbor treatment, but reversed and remanded the treatment of Minnesota Power's prepaid pension asset back to the MPUC. The Court directed the MPUC to determine the amount of Minnesota Power's prepaid pension asset to be included in rate base. The MPUC has not yet determined the next procedural steps in implementing the Court's decision.

 NOTE 4. REGULATORY MATTERS (Continued)
 Electric Rates (Continued)

 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 29, 2028. Under the agreement with SWL&P, no termination notice has been given. The rates included in these two contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power's authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.

 Minnesota Power's wholesale electric contracts with 13 other municipal customers were extended in January 2022 and are effective through 2029. These contracts are based on fixed prices for capacity and energy. The base energy charge for each year is adjusted annually for updated fuel and purchased power costs.

 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 March 5, 2024. On November 13, 2024, Minnesota Power submitted its latest transmission factor filing. Following approval of the filing by the MPUC, Minnesota Power will be authorized to include updated billing rates on customer bills.

 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 an order dated June 25, 2024.

 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 were approved by the MPUC in an order dated December 26, 2023. On October 8, 2024, Minnesota Power submitted its latest solar factor filing. Following approval of the filing by the MPUC, Minnesota Power will be authorized to include updated billing rates on customer bills.

 Fuel Adjustment Clause. Fuel and purchased power costs related to Minnesota Power's retail customers are recovered from customers through the fuel adjustment clause. The method of accounting for all Minnesota electric utilities is a monthly budgeted, forward-looking fuel adjustment clause with annual prudence review and true-up to actual allowed costs.

 Minnesota Power 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. The MPUC approved recovery of the regulatory asset in an order dated July 31, 2023; recovery of the regulatory asset began in the third quarter of 2023 and ended in mid-2024.

 Minnesota Power incurred lower fuel and purchased power costs in 2023 than those factored in its fuel adjustment forecast filed in May 2022 for 2023, which resulted in the recognition of a $ 15.5 million regulatory liability as of December 31, 2023. Minnesota Power requested to refund the regulatory liability over 12 months beginning in the third quarter of 2024 as part of its annual true-up filing submitted to the MPUC on March 1, 2024. In an order dated July 1, 2024, the MPUC approved the filing, and authorized Minnesota Power to refund the regulatory liability over 12 months beginning on September 1, 2024.

 Minnesota Power incurred higher fuel and purchased power costs in 2024 than those factored in its fuel adjustment forecast filed in May 2023 for 2024, which resulted in the recognition of a $ 4.5 million regulatory asset as of December 31, 2024. Minnesota Power expects to request recovery of the regulatory asset as part of its annual true-up filing with the MPUC in March 2025.

 Minnesota Power's filed its annual forecasted fuel and purchased power rates for 2025 on May 1, 2024, which was subsequently approved by the MPUC in an order dated November 8, 2024. The fuel and purchased power rates for Minnesota Power retail customers are based on this filing beginning January 1, 2025.

 NOTE 4. REGULATORY MATTERS (Continued)
 Electric Rates (Continued)

 Deferred Accounting Petition. On December 30, 2024, Minnesota Power submitted a petition with the MPUC seeking deferral accounting treatment for investigative costs and the increase in depreciation expense resulting from compliance costs that will be incurred related to the new Coal Combustion Rule (CCR) Legacy Rule, which was published in the Federal Register on May 8, 2024. (See Note 9. Commitments, Guarantees and Contingencies.) Compliance with the CCR Legacy Rule is expected to result in a significant increase to our MPUC-approved decommissioning costs for Boswell and Laskin. If the MPUC approves our request for deferral accounting treatment, these costs would be deferred for recovery to our next rate case or other regulatory proceeding. In 2024, we recorded depreciation expense related to this rule, of which $ 4.2 million pre-tax would be moved to a deferred tracking account for MPUC review through a future rate case or other proceeding if the MPUC approves our request for deferral accounting treatment. We are unable to predict the outcome of this proceeding.

 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 10.40 percent and a 55.00 percent equity ratio. The resolution of SWL&P's 2022 general rate case changed the allowed return on equity to 10.00 percent and maintained an equity ratio of 55.00 percent. (See 2022 Wisconsin General Rate Case.) The resolution of SWL&P's 2024 general rate case further changed the allowed return on equity to 9.80 percent and continued to maintain an equity ratio of 55.00 percent beginning January 1, 2025. (See 2024 Wisconsin General Rate Case.)

 2024 Wisconsin General Rate Case. On March 29, 2024, SWL&P filed a rate increase request for its electric, gas and water utilities with the PSCW. The filing sought an overall return on equity of 10.00 percent and a 55.00 percent equity ratio. On an annualized basis, the requested change would have increased rates by approximately 5.90 percent for retail customers and generated an estimated $ 7.3 million of additional revenue. In an order dated December 12, 2024, the PSCW approved an annual increase of approximately $ 5.5 million reflecting a return on equity of 9.80 percent and a 55.00 percent equity ratio. Final rates went into effect January 1, 2025.

 2022 Wisconsin General Rate Case. In an order dated December 20, 2022, the PSCW approved an annual increase of $ 3.3 million reflecting a return on equity of 10.00 percent and a 55.00 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 expects to file its next IRP in March 2025.

 Solar Energy Request For Proposals. On October 2, 2023, Minnesota Power filed a notice with the MPUC of its intent to issue a RFP for up to 300 MW of solar energy resources. Minnesota Power issued the RFP on November 15, 2023, which were accepted through January 17, 2024. Minnesota Power announced plans to build an 85 MW solar project and a 119.5 MW solar project in northern Minnesota, both of which are expected to be in service in mid-2027, subject to MPUC approval.

 Wind Energy Request For Proposals. On December 15, 2023, Minnesota Power filed a notice with the MPUC of its intent to issue a RFP for up to 400 MW of wind energy resources. Minnesota Power issued the RFP on February 15, 2024, which were accepted through April 11, 2024.

 NOTE 4. REGULATORY MATTERS (Continued)

 ECO Plan. 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 ECOs each year. On April 1, 2024, Minnesota Power submitted its 2023 ECO annual filing, formerly known as the conservation improvement program, detailing Minnesota Power's ECO plan results and proposed financial incentive, which was approved by the MPUC on November 8, 2024. As a result, Minnesota Power recognized revenue of $ 2.2 million in 2024 for the approved financial incentive ($ 2.2 million in 2023 and $ 1.9 million in 2022). The financial incentives are recognized in the period in which the MPUC approves the filing.

 On June 30, 2023, Minnesota Power submitted its triennial filing for 2024 through 2026 to the MPUC and Minnesota Department of Commerce, which outlines Minnesota Power's ECO spending and energy-saving goals for those years. Minnesota Power's investment goals are $ 12.7 million for 2025 and $ 12.8 million for 2026.

 MISO Return on Equity Complaints. MISO transmission owners, including ALLETE and ATC, had 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 was subject to various legal challenges related to the return on equity calculation and refund period ordered by the FERC. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the 2020 FERC order back to the FERC. On October 17, 2024, FERC ordered a return on equity of 9.98 percent, or 10.48 percent including an incentive adder for participation in a RTO, effective September 28, 2016. (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.

 Minnesota Distributed Solar Energy Standard. Minnesota law requires at least 3 percent of Minnesota Power's retail electric sales to be generated from distributed solar energy resources by 2030. Minnesota Power expects to need between 65 MW and 85 MW of distributed solar capacity to meet this requirement. On January 30, 2025, Minnesota Power issued a RFP seeking distributed solar projects as part of its compliance with this distributed solar energy standard. The RFP seeks proposals for solar generating facilities of 10 MW or less that will be connected to Minnesota Power's distribution system.

 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

 2024
 2023

 Current Regulatory Assets (a)

 Fuel Adjustment Clause (b)

 —
 $ 8.7

 Other
 $ 1.6
 0.6

 Total Current Regulatory Assets
 $ 1.6
 $ 9.3

 Non-Current Regulatory Assets

 Defined Benefit Pension and Other Postretirement Benefit Plans (c)

 $ 200.3
 $ 218.6

 Income Taxes (d)

 84.9
 88.1

 Asset Retirement Obligations (e)

 41.0
 37.7

 Taconite Harbor (g)

 17.3
 20.9

 Manufactured Gas Plant (h)

 11.6
 13.2

 Cost Recovery Riders (f)

 5.5
 33.8

 Fuel Adjustment Clause (b)

 4.5
 5.0

 PPACA Income Tax Deferral
 3.7
 3.9

 Other
 2.9
 4.2

 Total Non-Current Regulatory Assets
 $ 371.7
 $ 425.4

 Current Regulatory Liabilities (i)

 Provision for Interim Rate Refund
 $ 23.0
 —

 Fuel Adjustment Clause (b)

 7.2
 —

 Other
 1.3
 $ 3.9

 Total Current Regulatory Liabilities
 $ 31.5
 $ 3.9

 Non-Current Regulatory Liabilities

 Income Taxes (d)

 $ 292.7
 $ 310.0

 Wholesale and Retail Contra AFUDC (j)

 77.6
 78.0

 Plant Removal Obligations (k)

 74.2
 67.0

 Defined Benefit Pension and Other Postretirement Benefit Plans (c)

 40.7
 48.6

 Non-Jurisdictional Land Sales (l)

 59.7
 30.2

 Investment Tax Credits (m)

 17.8
 13.6

 Boswell Units 1 and 2 Net Plant and Equipment (n)

 6.7
 6.7

 Fuel Adjustment Clause (b)

 0.6
 15.5

 Other
 0.5
 4.4

 Total Non-Current Regulatory Liabilities
 $ 570.5
 $ 574.0

 (a)Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.
 (b)Fuel adjustment clause regulatory assets and liabilities 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)Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
 (f)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, 2024, will be recovered within the next two years.
 (g)In the first quarter of 2023, Minnesota Power retired Taconite Harbor Units 1 and 2. The remaining net book value was reclassified from property, plant and equipment to a regulatory asset on the Consolidated Balance Sheet when the units were retired. Minnesota Power expects to receive recovery of the remaining net book value from customers.
 (h)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.
 (i)Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.
 (j)Wholesale and retail contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.
 (k)Non-legal plant removal obligations included in retail customer rates that have not yet been incurred.
 (l)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.
 (m)North Dakota and federal investment tax credits expected to be realized from Minnesota Power's Bison facility and SWL&P's community solar facility that will be credited to retail customers primarily through future renewable cost recovery rider and rate filings as the tax credits are utilized.
 (n) 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.

 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.

 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.

 Assets Acquired

 $ 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

 $ 23.6

 Long-Term Debt Due Within One Year
 28.3

 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.

 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. In 2024, we invested $ 5.8 million in ATC. In total, we expect to invest approximately $ 18.3 million in 2025.

 ALLETE's Investment in ATC

 2024
 2023

 Equity Investment Beginning Balance
 $ 179.7
 $ 165.4

 Cash Investments
 5.8
 8.2

 Equity in ATC Earnings
 26.5
 23.1

 Distributed ATC Earnings
 ( 18.9)
 ( 18.3)

 Amortization of the Remeasurement of Deferred Income Taxes
 1.3
 1.3

 Equity Investment Ending Balance
 $ 194.4
 $ 179.7

 ATC Summarized Financial Data

 Balance Sheet Data

 2024
 2023

 Current Assets
 $ 126.6
 $ 115.2

 Non-Current Assets
 6,792.6
 6,337.0

 Total Assets
 $ 6,919.2
 $ 6,452.2

 $ 482.4
 $ 495.9

 3,083.4
 2,736.0

 Other Non-Current Liabilities
 545.0
 585.2

 Members' Equity
 2,808.4
 2,635.1

 Total Liabilities and Members' Equity
 $ 6,919.2
 $ 6,452.2

 Income Statement Data

 2024
 2023
 2022

 Revenue
 $ 911.3
 $ 818.9
 $ 751.2

 Operating Expense
 442.3
 407.6
 381.5

 Other Expense
 137.8
 131.7
 122.9

 Net Income
 $ 331.2
 $ 279.6
 $ 246.8

 ALLETE's Equity in Net Income
 $ 26.5
 $ 23.1
 $ 19.3

 ATC's authorized return on equity was 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. In August 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. On October 17, 2024, FERC ordered a return on equity of 9.98 percent, or 10.48 percent including an incentive adder for participation in a RTO, effective September 28, 2016.

 In addition, the FERC issued a Notice of Proposed Rulemaking in April 2021 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

 Equity Investment Balance as of December 31, 2023
 $ 151.5

 Equity in Nobles 2 Earnings (a)

 ( 1.5)

 Distributed Nobles 2 Earnings
 ( 4.3)

 Equity Investment Balance as of December 31, 2024
 $ 145.7

 (a)The Company also recorded net loss attributable to non-controlling interest of $ 11.7 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.

 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, 2024, and December 31, 2023. 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, 2024

 Total

 Investments (a)

 Available-for-sale – Equity Securities
 $ 8.6
 —
 —
 $ 8.6

 Available-for-sale – Corporate and Governmental Debt Securities (b)

 —
 $ 6.8
 —
 6.8

 Cash Equivalents
 8.5
 —
 —
 8.5

 $ 17.1
 $ 6.8
 —
 $ 23.9

 Liabilities:

 Deferred Compensation (c)

 —
 $ 21.1
 —
 $ 21.1

 Total Fair Value of Liabilities
 —
 $ 21.1
 —
 $ 21.1

 (a)Included in Other Non-Current Assets on the Consolidated Balance Sheet.
 (b)As of December 31, 2024, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $ 2.0 million, in one year to less than three years was $ 2.8 million, in three years to less than five years was $ 1.5 million and in five or more years was $ 0.5 million.
 (c)Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

 Fair Value as of December 31, 2023

 Total

 Investments (a)

 Available-for-sale – Equity Securities
 $ 8.7
 —
 —
 $ 8.7

 Available-for-sale – Corporate and Governmental Debt Securities
 —
 $ 6.0
 —
 6.0

 Cash Equivalents
 5.8
 —
 —
 5.8

 $ 14.5
 $ 6.0
 —
 $ 20.5

 Liabilities: (b)

 Deferred Compensation
 —
 —

 Total Fair Value of Liabilities
 —
 —

 (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, 2024 and 2023, 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

 Short-Term and Long-Term Debt (a)

 December 31, 2024
 $ 1,808.0
 $ 1,668.0

 December 31, 2023
 $ 1,799.4
 $ 1,670.6

 (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 $ 340.1 million as of December 31, 2024 ($ 331.2 million as of December 31, 2023). 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, 2024 and 2023, 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, 2024.

 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, 2024, and 2023, 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 $ 220 million and $ 395 million, respectively, as of December 31, 2024. (See Note 4. Regulatory Matters.) Minnesota Power also retired Taconite Harbor in the first quarter of 2023 consistent with its latest IRP. As part of the 2022 general retail rate case, the MPUC allowed recovery of the remaining book value of Taconite Harbor through 2026. 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, 2024, total short-term debt outstanding was $ 94.7 million ($ 111.4 million as of December 31, 2023), and consisted of long-term debt due within one year and included no unamortized debt issuance costs.

 As of December 31, 2024, we had consolidated bank lines of credit aggregating to $ 362.0 million ($ 423.1 million as of December 31, 2023), most of which expire in January 2027. We had $ 16.2 million outstanding in standby letters of credit and $ 20.0 million outstanding draws under our lines of credit as of December 31, 2024 ($ 19.4 million in standby letters of credit and $ 34.1 million outstanding draws as of December 31, 2023).

 Long-Term Debt. As of December 31, 2024, total long-term debt outstanding was $ 1,704.7 million ($ 1,679.9 million as of December 31, 2023) and included $ 8.6 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2025 is $ 94.7 million; $ 80.2 million in 2026; $ 182.5 million in 2027; $ 55.8 million in 2028; $ 220.3 million in 2029; and $ 1,174.5 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 April 23, 2024, ALLETE issued $ 100 million of its First Mortgage Bonds (Bonds) to certain institutional buyers in the private placement market. The Bonds, which bear interest at 5.72 percent, will mature on April 30, 2039 and pay interest semi-annually in April and October of each year, commencing on October 30, 2024. 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.

 On July 31, 2024, ALLETE issued a notice to the holders of its 2.65 percent senior notes due September 10, 2025, ("2025 Notes") regarding the Company's exercise of its option to prepay all of the issued and outstanding 2025 Notes. ALLETE prepaid all $ 150 million in aggregate principal amount of the 2025 Notes on September 5, 2024. The 2025 Notes were prepaid at 100 percent of their principal amount, plus accrued and unpaid interest.

 On September 5, 2024, ALLETE issued and sold $ 150 million of senior unsecured notes ("Notes") to certain institutional buyers in the private placement market. The Notes 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. Of the Notes issued and sold, $ 100 million of the Notes bear interest at a rate of 5.94 percent and mature on September 5, 2029, and $ 50 million of the Notes bear interest at a rate of 6.18 percent and mature on September 5, 2034. Interest on the Notes will be payable semi-annually on March 5 and September 5 of each year, commencing on March 5, 2025. The Company has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes were used for refinancing of debt and general corporate purposes.

 Pursuant to the Merger Agreement, we may incur certain forms of indebtedness only with the written consent of Alloy Parent. (See Note 15. Agreement and Plan of Merger.)

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

 2024
 2023

 First Mortgage Bonds

 3.69 % Series Due 2024

 —
 $ 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
 75.0

 4.98 % Series Due 2033

 125.0
 125.0

 5.69 % Series Due 2036

 50.0
 50.0

 5.72 % Series Due 2039

 100.0
 —

 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

 —
 9.5

 Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025
 27.8
 27.8

 Revolving Credit Facility Variable Rate Due 2027
 20.0
 —

 Senior Unsecured Notes 2.65 % Due 2025

 —
 150.0

 Senior Unsecured Notes 3.11 % Due 2027

 80.0
 80.0

 Senior Unsecured Notes 5.94 % Due 2029

 100.0
 —

 Senior Unsecured Notes 6.18 % Due 2034

 50.0
 —

 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

 Other Long-Term Debt, 2024 Weighted Average Rate 4.47 % Due 2025 – 2051

 53.2
 95.1

 Unamortized Debt Issuance Costs
 ( 8.6)
 ( 8.1)

 Total Long-Term Debt
 1,799.4
 1,791.3

 Less: Due Within One Year
 94.7
 111.4

 Net Long-Term Debt
 $ 1,704.7
 $ 1,679.9

 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, 2024, our ratio was approximately 0.36 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; however, under the Merger Agreement, the Company has agreed not to declare or pay dividends except for quarterly cash dividends payable by us in respect of shares of our common stock on a schedule consistent with our past practices in an amount not to exceed 5 percent per share more than the dividend payable during the prior 12-month period, subject to certain other exceptions. (See Note 15. Agreement and Plan of Merger.) As of December 31, 2024, 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, 2024:

 2025
 2026
 2027
 2028
 2029
 Thereafter

 Capital Purchase Obligations
 $ 192.9
 $ 37.4
 $ 91.8
 $ 59.8
 $ 5.6
 $ 13.7

 Easements (a)

 $ 27.2
 $ 8.3
 $ 8.4
 $ 8.5
 $ 8.5
 $ 212.0

 PPAs (b)

 $ 134.6
 $ 136.0
 $ 130.1
 $ 133.3
 $ 134.1
 $ 797.3

 Other Purchase Obligations (c)

 $ 31.8
 $ 9.6
 $ 10.3
 —
 —
 —

 (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, these 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, 2024, Square Butte had total debt outstanding of $ 168.9 million. Annual debt service for Square Butte is expected to be approximately $ 30.6 million in 2025 and $ 32.1 million in 2026 of which Minnesota Power's obligation is 50 percent. Fuel expenses are recoverable through Minnesota Power's fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.

 Power Purchase and Sales Agreements (Continued)

 Minnesota Power's cost of power purchased from Square Butte during 2024 was $ 87.7 million ($ 86.2 million in 2023; $ 82.7 million in 2022). 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 $ 4.9 million in 2024 ($ 5.5 million in 2023; $ 5.1 million in 2022). 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, 2024:

 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, 2024:

 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 provided for 75 MW of capacity from June 1, 2022, through May 31, 2023, and increased 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 41 percent in 2024 ( 37 percent in 2023 and 32 percent in 2022). (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 2027. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2027. 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, as well as natural gas and biomass. 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 as well as consideration of current rules, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. Minnesota Power will continue to monitor ongoing CSAPR rulemakings and compliance implementation, including the EPA's Good Neighbor Rule which modifies certain aspects of the CSAPR's program scope and extent (see EPA Good Neighbor Plan for 2015 Ozone NAAQS).

 National Ambient Air Quality Standards (NAAQS). The EPA is required to review each 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 the EPA has recently reassessed several primary and secondary NAAQS for NOx, SO2, and particulate matter. Implementation of the EPA's February 2024 final rule lowering the annual primary standard for fine particulate matter began on May 6, 2024. On December 27, 2024, the EPA published a final rule in the Federal Register revising the secondary SO2 NAAQS while retaining the NOX and particulate matter secondary standards, with a final rule effective date of January 27, 2025. Anticipated timelines and compliance costs related to this and other potential NAAQS revisions cannot yet be estimated but costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

 Environmental Matters (Continued)

 EPA Good Neighbor Plan for 2015 Ozone NAAQS. On June 5, 2023, after disapproving state implementation plans, the EPA published a final Federal Implementation Plan (FIP) rule in the Federal Register, 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). In its justification for the final rule, the EPA asserted that 23 states, including Minnesota, were modeled as significant contributors to downwind states' challenges in attaining or maintaining ozone NAAQS compliance within their state borders. The Good Neighbor Plan is designed 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. The final rule imposed restrictions on fossil-fuel fired power plants in 22 states and on certain industrial sources in 20 states, with implementation occurring through changes to the existing CSAPR program for power plants.

 Since the EPA partially disapproved the Good Neighbor State Implementation Plans (SIPs) for the states of Minnesota and Wisconsin, among others, Minnesota became subject to the final Good Neighbor Plan. However, Minnesota Power and a coalition of other Minnesota utilities and industry (the parties) co-filed challenges to the EPA's final Minnesota SIP disapproval, submitting a petition for reconsideration and stay to the EPA, and a petition for judicial review to the Eighth Circuit Court. The parties are challenging and requesting reconsideration of certain technical components of the EPA's review and subsequent partial disapproval of the state of Minnesota's SIP. On July 5, 2023, the Eighth Circuit Court granted a stay of the SIP disapproval preventing the Good Neighbor Plan from taking effect in Minnesota; oral arguments occurred on October 22, 2024. On April 4, 2024, the EPA published a partial denial of several administrative reconsideration and stay petitions, including from the Minnesota coalition. On September 29, 2023, the EPA issued an updated final interim rule addressing the stays in Minnesota and five other states, formally delaying the effective date of the final FIP for states with active stays in place. The state of Minnesota therefore did not become subject to compliance obligations for the 2023 or 2024 ozone seasons.

 Future compliance obligations will depend on resolution of the stay and outcomes of related litigation. Additional challenges have been filed against the final FIP rule by the Minnesota coalition parties and other entities, although the Minnesota coalition FIP challenge is currently in abeyance pending resolution of the SIP disapproval case. On June 27, 2024, the U.S. Supreme Court granted an emergency stay of the FIP rule requested by several states and industry groups, staying enforcement pending the D.C. Circuit's review and any petition for writ of certiorari. In response to the U.S. Supreme Court's stay order, the EPA published a third interim rule in the Federal Register on November 6, 2024, staying the effectiveness of the Good Neighbor FIP in the 10 remaining covered states, including Wisconsin. Anticipated timelines and compliance costs related to final Good Neighbor Plan compliance cannot yet be estimated due to uncertainties about SIP approval resolution, implementation timing, FIP rule outcome, and allowance costs and facility emissions during the ozone season. 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.

 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, which applied to Minnesota Power's Hibbard Renewable Energy Center and Rapids Energy Center. Compliance consisted largely of adjustments to fuels and operating practices and compliance costs were not material. After this initial rulemaking, litigation from 2016 through 2018 resulted in court orders directing that the EPA reconsider certain aspects of the regulation. A final rule incorporating these revisions became effective in December 2022, with a compliance deadline of October 6, 2025. Compliance costs are not expected to be material.

 EPA Mercury and Air Toxics Standards (MATS) Rule. On April 25, 2024, the EPA published a final rule to revise the existing 2012 MATS Rule, which regulates air emissions of hazardous air pollutants from coal- and oil-fired electric generating units (EGUs). The final rule eliminates certain MATS compliance flexibility, lowers the particulate emission standard for all coal-fired EGUs, and reduces the mercury emission standard for lignite-fired EGUs. The rule became effective July 8, 2024, with compliance required beginning July 6, 2027. The MATS regulation applies at Minnesota Power's Boswell facility, which is currently well-controlled for these emissions and already complying with some of the new requirements. The Company anticipates the new rule will not have material impacts at Boswell. However, compliance costs cannot yet be fully estimated, and recovery of any additional costs would be sought through a rate proceeding. Litigation against the EPA's latest MATS Rule revision from a number of U.S. states as well as several companies and industry groups is ongoing. Motions to stay the rule were denied by the U.S. Court of Appeals for the D.C. Circuit on August 6, 2024, and the U.S. Supreme Court on October 4, 2024.

 Environmental Matters (Continued)

 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.

 EPA Regulation of GHG Emissions. On April 25, 2024, the EPA issued several final greenhouse gas regulations to establish emissions standards and guidelines for fossil fuel-fired electric generating units (EGUs) under Section 111 of the Clean Air Act (CAA). The final rules revise new source performance standards (NSPS) for new, modified and reconstructed EGUs (Section 111(b) of the CAA) and creates new emission guidelines for existing EGUs (Section 111(d) of the CAA). The action also officially repeals the predecessor regulation "Affordable Clean Energy Rule", first issued in 2019 and later vacated in 2021. Compliance will be required beginning January 1, 2030, for existing sources, and upon commencing operation of new units. The 111(d) rule also requires states to submit plans to provide for the establishment, implementation and enforcement of performance standards for existing sources. States must submit either a state plan or negative declaration letter to the EPA by May 11, 2026.

 The final Section 111 rules apply to several Company assets, including existing EGUs at the Boswell and Laskin facilities as well as the proposed combined cycle natural gas-fired generating facility, Nemadji Trail Energy Center. The Company anticipates compliance with the rules may require operational or planning adjustments. The state implementation plan process for Section 111(d) existing units will also be a factor in determining specific requirements and timing. We are unable to predict compliance costs at this time; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. The Company is also monitoring litigation of the final Section 111 rules, which began when the rules were published in the Federal Register on May 9, 2024, and continues in federal court. Both the D.C. Circuit and the U.S. Supreme Court have declined requests to block the rule from becoming effective while litigation is ongoing. Oral arguments in the D.C. Circuit occurred on December 6, 2024, with a merits decision currently expected by mid-2025. Outcomes from ongoing litigation may impact both the timing of rule effectiveness and the ultimate compliance obligations required by the rule.

 Environmental Matters (Continued)

 Water. The Clean Water Act requires NPDES permits be obtained from the EPA or delegated state 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 Best Available Control Technology (BACT) for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In October 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 set 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.

 On May 9, 2024, the EPA finalized revisions to the 2020 ELG rule. The final rule establishes zero discharge limitations for bottom ash transport water, FGD wastewater, and combustion residual leachate. A definition for legacy wastewater was established, with deferral to state permit programs for setting discharge limits based on best professional judgment. The rule maintains exemptions for units permanently ceasing coal combustion by 2028 and adds a new subcategory for units that are retiring by 2032 and have already complied with either the 2015 or 2020 ELG rules. Additionally, the rule establishes mercury and arsenic limitations for functionally equivalent discharges of leachate via groundwater to surface water. Compliance deadlines are determined by the applicable state permitting authority through permit incorporation as soon as July 8, 2024, but no later than December 31, 2029.

 Bottom ash transport and FGD wastewater ELGs are not expected to have a significant impact on Minnesota Power operations. Zero leachate discharge requirements have the potential to impact dewatering associated with the closed Taconite Harbor dry ash landfill. New limitations for arsenic and mercury related to functionally equivalent (groundwater to surface water) discharges are not currently anticipated to impact Minnesota Power facilities.

 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.

 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.

 The federal Clean Water Act requires the MPCA to update the state's impaired water list every two years. Beginning in 2021 through the latest release approved by the EPA in April 2024, this list now includes Minnesota lakes and streams identified as wild rice waters that are listed for sulfate impairment. The 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 or its customers, if any. Minnesota Power would seek recovery of additional costs through a rate proceeding.

 Environmental Matters (Continued)

 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.

 Boswell Ash Wastewater Spill. On August 12, 2024, Minnesota Power received a Notice of Violation (NOV) from the MPCA, related to the spill at Boswell from a pipeline carrying ash wastewater from an inactive onsite storage pond to Blackwater Creek, which the Company reported on July 16, 2024. Minnesota Power responded to the MPCA NOV, clarifying certain statements made by the MPCA, as well as providing a written report and required plans. We are awaiting a proposed Stipulation Agreement from the MPCA. Minnesota Power continues to work with state and federal agencies to evaluate and mitigate the impacts from this event. We are unable to predict the mitigation or other costs related to the ash wastewater spill at this time; however, the costs could be material.

 Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published a 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 included 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 12 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 compliance costs through evaluation of beneficial re-use and recycling of CCR. In 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule, which resulted in a change to the status of existing clay-lined impoundments at Boswell being considered unlined. In September 2020, the EPA finalized the CCR Part A Rule, which required all unlined impoundments to cease disposal and initiate closure. Upon completion of dry ash conversion activities, Boswell ceased disposal in both impoundments in September 2022. Both impoundments are now inactive and have initiated closure.

 On May 8, 2024, the EPA's final CCR Legacy Impoundment Rule was published in the Federal Register. The final rule expands the scope of units regulated under the CCR rule to include legacy ponds (inactive surface impoundments at inactive facilities) and creates a new category of units called CCR management units (CCRMU), which includes inactive and closed impoundments and landfills as well as other non-containerized accumulations of CCR. The final rule requires all regulated generating facilities to evaluate and identify past deposits of CCR materials on their sites and close or re-close existing CCR units to meet current closure standards, as well as install groundwater monitoring systems, conduct groundwater monitoring, and implement groundwater corrective actions as necessary. The Final Rule requires a Facility Evaluation Report by February 2027, which will identify regulated units and applicable requirements. Additionally, the EPA finalized portions of the proposed CCR Part B Rule, which allows CCR units to certify closure while conducting groundwater remediation activities. Impacts to previously closed CCR units at Boswell and Laskin are anticipated. Compliance costs for Minnesota Power's Boswell and Laskin facilities are estimated to be between approximately $ 50 million and $ 85 million and are expected to be incurred over the next 10 years based on our preliminary assessment. These estimates may be revised as Minnesota Power completes the required facility evaluations. Minnesota Power is expected to seek recovery of these costs through a rate proceeding.

 Additionally, the EPA released a proposed CCR 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. A final rule establishing the remaining CCR beneficial reuse requirements is expected but has been moved to EPA's long term rulemakings, without a publication target date currently. According to its latest Unified Agenda, the EPA had planned to publish the final CCR federal permit rule implementing a permitting program for tribal lands and nonparticipating states in December 2024, but that did not occur.

 Other Environmental Matters

 Manufactured Gas Plant Site. SWL&P has completed a portion of the remediation activities at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. We continue working with the Wisconsin Department of Natural Resources on the remaining remediation at the site and surrounding properties. As of December 31, 2024, SWL&P has recorded a liability of approximately $ 0.3 million for remediation costs at this site. SWL&P has recorded the recovery of the remediation costs associated with the site as a regulatory asset as we expect recovery of these costs to be allowed by the PSCW.

 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, 2024, we had $ 134.7 million of outstanding letters of credit issued, including those issued under our revolving credit facility, and $ 122.2 million in outstanding surety bonds. We do not believe it is likely that any of these outstanding letters of credit will be drawn upon.

 In 2024, under the tax credit transferability provision of the Inflation Reduction Act, we entered into agreements with third parties to sell a portion of our renewable tax credits. ALLETE has indemnified the parties for the value of renewable tax credits sold to date of approximately $ 64.3 million.

 Regulated Operations. As of December 31, 2024, we had $ 23.3 million outstanding in standby letters of credit and surety bonds at our Regulated Operations which are pledged as security to MISO, the NDPSC and a state agency.

 ALLETE Clean Energy. ALLETE Clean Energy is party to PSAs that expire in various years between 2027 and 2039. As of December 31, 2024, ALLETE Clean Energy has $ 94.5 million outstanding in standby letters of credit and surety bonds, the majority of which are pledged as security under these PSAs.

 Corporate and Other.

 BNI Energy. As of December 31, 2024, BNI Energy had surety bonds outstanding of $ 88.8 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, 2024, ALLETE South Wind has $ 10.1 million outstanding in standby letters of credit, related to our portion of the security requirements relative to our ownership in Nobles 2.

 South Shore Energy. As of December 31, 2024, South Shore Energy had $ 29.7 million outstanding in standby letters of credit pledged as security in connection with the development of NTEC.

 New Energy. As of December 31, 2024, New Energy had $ 10.4 million outstanding in standby letters of credit related to the development of renewable energy projects.

 ALLETE Properties. As of December 31, 2024, ALLETE Properties had surety bonds outstanding 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 will be drawn upon.

 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, 2024, we owned 32 percent of the assessable land in the Town Center District ( 33 percent as of December 31, 2023). As of December 31, 2024, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $ 0.7 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.

 Arbitration Proceeding. In the first quarter of 2023, an ALLETE Clean Energy subsidiary initiated arbitration proceedings seeking damages against a counterparty for non-performance under a contract. Arbitration hearings were held in June and July 2023, and a final arbitration ruling was issued in favor of ALLETE Clean Energy's subsidiary in September 2023. The final arbitration ruling awarded $ 68.3 million to ALLETE Clean Energy's subsidiary, which included prejudgment interest of $ 5.1 million, recovery of $ 3.6 million of arbitration-related costs, and resulted in the recognition of a $ 58.4 million pre-tax gain in the third quarter of 2023. The arbitration ruling also resulted in the receipt of approximately $ 60 million of cash, net of distribution to non-controlling interest, in the third quarter of 2023.

 Merger-related Complaints. Three complaints have been filed against ALLETE and its directors. The first was filed on July 1, 2024, in the U.S. District Court for the Southern District of New York, alleging violation of Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, disclosure deficiency in the Preliminary Proxy, and seeking to enjoin the transaction until certain disclosures are corrected. On September 3, 2024, that complaint was voluntarily dismissed without prejudice. Two additional complaints were filed on August 6, 2024, and August 7, 2024, in the New York State Supreme Court, alleging negligent misrepresentation and negligence related to alleged deficiencies in the Preliminary Proxy. Those complaints have not been served on any defendant. The Company believes that the remaining complaints are without merit.

 NOTE 10. COMMON STOCK AND EARNINGS PER SHARE

 Summary of Common Stock
 Equity

 Thousands

 Balance as of December 31, 2021
 53,220
 $ 1,536.7

 Employee Stock Purchase Plan
 0.9

 Invest Direct
 14.9

 Share-Based Compensation
 5.3

 Equity Issuance
 3,680
 223.7

 Balance as of December 31, 2022
 57,237
 1,781.5

 Employee Stock Purchase Plan
 0.8

 Invest Direct
 13.3

 Share-Based Compensation
 8.1

 Balance as of December 31, 2023
 57,561
 1,803.7

 Employee Stock Purchase Plan
 0.9

 Invest Direct
 12.4

 Share-Based Compensation
 6.2

 Balance as of December 31, 2024
 57,882
 $ 1,823.2

 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, 2024. For the year ended December 31, 2024, no shares of common stock were issued under this agreement ( none in 2023; none in 2022). 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.

 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

 Basic
 Securities

 Millions Except Per Share Amounts

 2024

 Average Common Shares
 57.7
 0.1
 57.8

 Earnings Per Share
 $ 3.11
 $ 3.10

 2023

 Average Common Shares
 57.3
 0.1
 57.4

 Earnings Per Share
 $ 4.31
 $ 4.30

 2022

 Average Common Shares
 55.9
 0.1
 56.0

 Earnings Per Share
 $ 3.38
 $ 3.38

 NOTE 11. INCOME TAX EXPENSE

 Income Tax Expense

 2024
 2023
 2022

 Current Income Tax Expense (a)

 Federal
 $ 8.4
 $ 9.4
 $ 1.2

 State
 12.1
 0.9
 6.1

 Total Current Income Tax Expense
 $ 20.5
 $ 10.3
 $ 7.3

 Deferred Income Tax Expense (Benefit)

 Federal (b)

 $( 20.1)
 $( 6.0)
 $( 32.8)

 State (c)

 5.0
 24.0
 ( 5.2)

 Investment Tax Credit Amortization
 ( 0.7)
 ( 0.4)
 ( 0.5)

 Total Deferred Income Tax Expense (Benefit)
 $( 15.8)
 $ 17.6
 $( 38.5)

 Total Income Tax Expense (Benefit)
 $ 4.7
 $ 27.9
 $( 31.2)

 (a)For the years ended December 31, 2024, the federal current tax expense was partially offset by tax credits. For the years ended December 31, 2023 and 2022, the federal current tax expense was partially offset by tax credits and NOLs.
 (b)The federal deferred income tax benefit is primarily due to tax credits. For the year ended December 31, 2023, the federal deferred income tax benefit was partially offset by deferred partnership income.
 (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

 2024
 2023
 2022

 Income Before Non-Controlling Interest and Income Taxes
 $ 126.4
 $ 206.8
 $ 100.1

 Statutory Federal Income Tax Rate
 %
 %
 %

 Income Taxes Computed at Statutory Federal Rate
 $ 26.5
 $ 43.4
 $ 21.0

 Increase (Decrease) in Tax Due to:

 State Income Taxes – Net of Federal Income Tax Benefit
 13.5
 19.7
 8.6

 Deferred Revaluation – Net of Federal Income Tax Benefit
 —
 —
 ( 7.9)

 Production Tax Credits (a)

 ( 32.4)
 ( 31.6)
 ( 50.7)

 Investment Tax Credits (a)

 ( 4.8)
 ( 5.8)
 ( 4.1)

 Regulatory Differences – Excess Deferred Tax Benefit
 ( 9.9)
 ( 9.9)
 ( 9.1)

 Non-Controlling Interest
 11.0
 13.3
 11.2

 AFUDC - Equity
 ( 1.5)
 ( 1.3)
 ( 1.1)

 Transaction Costs
 4.7
 —
 —

 Other
 ( 2.4)
 0.1
 0.9

 Total Income Tax Expense (Benefit)
 $ 4.7
 $ 27.9
 $( 31.2)

 (a)For the years ended December 31, 2023 and 2024, the credits are presented net of any estimated discount on the sale of certain credits.

 The effective tax rate was an expense of 3.7 percent for 2024 (expense of 13.5 percent for 2023; benefit of 31.2 percent for 2022). The 2024, 2023 and 2022 effective tax rates were primarily impacted by tax credits and non-controlling interests in subsidiaries.

 NOTE 11. INCOME TAX EXPENSE (Continued)

 Deferred Income Tax Assets and Liabilities

 2024
 2023

 Deferred Income Tax Assets

 Deferred Gain - Land Sales
 $ 8.3

 Employee Benefits and Compensation
 20.5
 29.3

 Property-Related
 52.0
 58.1

 NOL Carryforwards
 10.6
 13.0

 Tax Credit Carryforwards
 486.9
 557.4

 Power Sales Agreements
 7.3
 9.0

 Regulatory Liabilities
 84.0
 89.0

 Other
 4.2
 0.6

 Gross Deferred Income Tax Assets
 682.0
 764.7

 Deferred Income Tax Asset Valuation Allowance
 ( 44.9)
 ( 58.0)

 Total Deferred Income Tax Assets
 $ 637.1
 $ 706.7

 Deferred Income Tax Liabilities

 Deferred Gain
 $ 7.1
 $ 7.9

 Property-Related
 619.7
 632.0

 Regulatory Asset for Benefit Obligations
 46.0
 48.1

 Unamortized Investment Tax Credits
 29.0
 29.6

 Partnership Basis Differences
 164.3
 156.5

 Regulatory Assets
 24.4
 25.3

 Total Deferred Income Tax Liabilities
 $ 890.5
 $ 899.4

 Net Deferred Income Taxes (a)

 $ 253.4
 $ 192.7

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

 NOL and Tax Credit Carryforwards

 2024
 2023

 Federal Tax Credit Carryforwards
 $ 424.7
 $ 480.4

 State NOL Carryforwards (a)

 $ 258.8
 $ 280.9

 State Tax Credit Carryforwards (b)

 $ 19.9
 $ 21.5

 (a)Pre-tax amounts; state NOL carryforwards net of a $ 9.7 million valuation allowance.
 (b)Net of a $ 42.3 million valuation allowance as of December 31, 2024 ($ 55.4 million as of December 31, 2023).

 The federal tax credit carryforward periods expire between 2035 and 2044. We expect to fully utilize the tax credit carryforwards; therefore, no federal valuation allowance has been recognized as of December 31, 2024. The apportioned state NOL, capital loss and tax credit carryforward periods expire between 2025 and 2045. 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.

 NOTE 11. INCOME TAX EXPENSE (Continued)

 Gross Unrecognized Income Tax Benefits
 2024
 2023
 2022

 Balance at January 1
 $ 1.1
 $ 1.3
 $ 1.3

 Reductions for Tax Positions Related to Prior Years
 —
 ( 0.2)
 —

 Balance as of December 31
 $ 1.1
 $ 1.1
 $ 1.3

 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, 2024, included $ 0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

 As of December 31, 2024, we had accrued interest of $ 0.2 million ($ 0.1 million as of December 31, 2023; none as of December 31, 2022) 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 2024, 2023 and 2022. There were no penalties recognized in 2024, 2023 or 2022. 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 Minnesota for the tax years 2020 through 2022. ALLETE has no open federal audits, and is no longer subject to federal examination for years before 2021 or state examination for years before 2020. Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns.

 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 $ 25.0 million in cash contributions to the plan trusts in 2024 ($ 17.3 million in 2023; none in 2022). We also have a defined contribution RSOP covering substantially all employees. The 2024 plan year employer contributions totaled $ 15.7 million ($ 13.7 million for the 2023 plan year; $ 12.0 million for the 2022 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. The postretirement life plan was amended in 2014 to close the plan to non-union employees retiring after 2015, and in 2018, the plan was amended to limit the benefit level for union employees retiring after 2018. In 2023, the postretirement health care plan was amended to change the company contribution to an annual stipend for certain retirees. 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 2024, no contributions were made to the VEBAs ( none in 2023; none in 2022) and no contributions were made to the grantor trusts ( none in 2023; none in 2022).

 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 15, 2025, we contributed $ 19.1 million in cash to the defined benefit pension plans, and do not expect to make additional cash contributions to the defined benefit pension plans in 2025. We do no t expect to make any contributions to the defined benefit postretirement health and life plans in 2025.

 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.

 Pension Obligation and Funded Status

 2024
 2023

 Accumulated Benefit Obligation
 $ 701.7
 $ 729.5

 Change in Benefit Obligation

 Obligation, Beginning of Year
 $ 746.3
 $ 739.7

 Service Cost
 6.6
 6.5

 Interest Cost
 38.6
 40.5

 Actuarial (Gain) Loss (a)

 ( 17.1)
 13.9

 Benefits Paid
 ( 61.9)
 ( 60.9)

 Participant Contributions
 7.0
 6.6

 Obligation, End of Year
 $ 719.5
 $ 746.3

 Change in Plan Assets

 Fair Value, Beginning of Year
 $ 589.0
 $ 568.6

 Actual Return on Plan Assets
 43.0
 55.1

 Employer Contribution (b)

 34.0
 26.2

 Benefits Paid
 ( 61.9)
 ( 60.9)

 Fair Value, End of Year
 $ 604.1
 $ 589.0

 Funded Status, End of Year
 $( 115.4)
 $( 157.3)

 Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:

 $( 1.9)
 $( 2.1)

 Non-Current Liabilities
 $( 113.5)
 $( 155.2)

 (a) The actuarial gain in 2024 was primarily the result of increases in discount rates. The actuarial loss in 2023 was primarily the result of decreases in discount rates.
 (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.

 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 primarily of a net loss of $ 235.2 million as of December 31, 2024 (net loss of $ 256.9 million as of December 31, 2023).

 Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet

 2024
 2023

 Net Loss
 $( 235.2)
 $( 256.9)

 Prior Service Cost
 ( 0.1)
 —

 Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)
 119.9
 99.6

 Total Net Pension Amounts Recognized in Consolidated Balance Sheet
 $( 115.4)
 $( 157.3)

 Components of Net Periodic Pension Cost

 2024
 2023
 2022

 Service Cost
 $ 6.6
 $ 6.5
 $ 9.3

 Non-Service Cost Components (a)

 Interest Cost
 38.6
 40.5
 27.2

 Expected Return on Plan Assets
 ( 44.8)
 ( 43.8)
 ( 41.5)

 Amortization of Loss
 6.5
 5.8
 11.4

 Amortization of Prior Service Credit
 ( 0.1)
 ( 0.1)
 ( 0.1)

 Net Pension Cost
 $ 6.8
 $ 8.9
 $ 6.3

 (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

 2024
 2023

 Net (Gain) Loss
 $( 15.2)
 $ 2.5

 Amortization of Prior Service Credit
 0.1
 0.1

 Amortization of Loss
 ( 6.5)
 ( 5.7)

 Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
 $( 21.6)
 $( 3.1)

 Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets

 2024
 2023

 Projected Benefit Obligation
 $ 719.5
 $ 746.3

 Accumulated Benefit Obligation
 $ 701.7
 $ 729.5

 Fair Value of Plan Assets
 $ 604.1
 $ 589.0

 Postretirement Health and Life Obligation and Funded Status

 2024
 2023

 Change in Benefit Obligation

 Obligation, Beginning of Year
 $ 73.9
 $ 110.4

 Service Cost
 1.5
 2.0

 Interest Cost
 3.9
 5.6

 Actuarial Gain (a)

 ( 1.9)
 ( 9.3)

 Benefits Paid
 ( 6.4)
 ( 8.1)

 Participant Contributions
 1.4
 2.4

 Plan Amendments (b)

 —
 ( 29.1)

 Obligation, End of Year
 $ 72.4
 $ 73.9

 Change in Plan Assets

 Fair Value, Beginning of Year
 $ 173.8
 $ 162.6

 Actual Return on Plan Assets
 14.8
 20.3

 Employer Contribution (Withdrawal)
 ( 9.4)
 ( 3.4)

 Participant Contributions
 1.4
 2.4

 Benefits Paid
 ( 6.4)
 ( 8.1)

 Fair Value, End of Year
 $ 174.2
 $ 173.8

 Funded Status, End of Year
 $ 101.8
 $ 99.9

 Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:

 Non-Current Assets
 $ 107.6
 $ 106.3

 $( 0.2)
 $( 0.2)

 Non-Current Liabilities
 $( 5.6)
 $( 6.2)

 (a)The actuarial gain in 2024 was primarily the result of increases in discount rates and the actual return on plan assets exceeding the expected return on plan assets. The actuarial gain in 2023 was primarily the result of the actual return on plan assets exceeding the expected return on plan assets.
 (b)In 2023, the postretirement health care plan was amended to change the company contribution to an annual stipend for certain retirees.

 According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $ 13.4 million in irrevocable grantor trusts included in Other Non-Current Assets on the Consolidated Balance Sheet as of December 31, 2024 ($ 12.8 million as of December 31, 2023).

 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

 2024
 2023

 Net Gain
 $( 27.1)
 $( 24.8)

 Prior Service Credit
 ( 22.1)
 ( 33.8)

 Total Unrecognized Postretirement Health and Life Credit
 $( 49.2)
 $( 58.6)

 Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet

 2024
 2023

 Net Gain (a)

 $ 27.1
 $ 24.8

 Prior Service Credit
 22.1
 33.8

 Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)

 52.6
 41.3

 Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
 $ 101.8
 $ 99.9

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

 Components of Net Periodic Postretirement Health and Life Cost

 2024
 2023
 2022

 Service Cost
 $ 1.5
 $ 2.0
 $ 3.0

 Non-Service Cost Components (a)

 Interest Cost
 3.9
 5.6
 4.4

 Expected Return on Plan Assets
 ( 11.1)
 ( 11.4)
 ( 9.6)

 Amortization of (Gain) Loss
 ( 3.2)
 ( 2.7)
 0.4

 Amortization of Prior Service Credit
 ( 11.7)
 ( 8.5)
 ( 7.5)

 Net Postretirement Health and Life Credit
 $( 20.6)
 $( 15.0)
 $( 9.3)

 (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

 2024
 2023

 Net Gain
 $( 5.6)
 $( 18.3)

 Prior Service Credit Arising During the Period
 —
 ( 29.1)

 Amortization of Prior Service Credit
 11.7
 8.4

 Amortization of Gain
 3.2
 2.7

 Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
 $ 9.3
 $( 36.3)

 Estimated Future Benefit Payments
 Postretirement Health and Life

 2025
 $ 59.3
 $ 6.0

 2026
 $ 58.6
 $ 6.0

 2027
 $ 58.2
 $ 6.1

 2028
 $ 57.9
 $ 6.1

 2029
 $ 57.5
 $ 6.2

 Years 2030 – 2034
 $ 272.7
 $ 31.2

 Weighted Average Assumptions Used to Determine Benefit Obligation

 2024
 2023

 Discount Rate

 5.78 %
 5.39 %

 Postretirement Health and Life
 5.79 %
 5.42 %

 Rate of Compensation Increase
 3.49 %
 3.52 %

 Health Care Trend Rates

 Trend Rate
 7.00 %
 7.00 %

 Ultimate Trend Rate
 5.00 %
 5.00 %

 Year Ultimate Trend Rate Effective
 2038
 2038

 Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs

 2024
 2023
 2022

 Discount Rate

 5.38 %
 5.70 %
 3.28 %

 Postretirement Health and Life
 5.42 %
 5.89 %
 3.09 %

 Expected Long-Term Return on Plan Assets

 6.84 %
 6.83 %
 6.00 %

 Postretirement Health and Life
 6.28 %
 6.33 %
 5.41 %

 Rate of Compensation Increase
 3.52 %
 3.58 %
 3.58 %

 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, 2024, considered a modified PRI-2012 mortality table and MP-2021 mortality projection scale.

 Actual Plan Asset Allocations
 Postretirement
 Health and Life (a)

 2024
 2023
 2024
 2023

 Equity Securities
 %
 %
 %
 %

 Fixed Income Securities
 %
 %
 %
 %

 %
 %
 —
 —

 %
 %
 %
 %

 (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, 2024 ( no shares as of December 31, 2023).

 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 capitalization, 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, 2024:

 Plan Asset Target Allocations
 Postretirement
 Health and Life (a)

 Equity Securities
 %
 %

 Fixed Income Securities
 %
 %

 %
 —

 %
 %

 (a)Includes VEBAs and irrevocable grantor trusts.

 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.)

 Pension Fair Value

 Fair Value as of December 31, 2024

 Total

 Equity Securities:

 U.S. Large-cap (a)

 $ 73.2
 —
 —
 $ 73.2

 U.S. Mid-cap Growth (a)

 35.1
 —
 —
 35.1

 U.S. Small-cap (a)

 31.6
 —
 —
 31.6

 International
 102.5
 $ 99.1
 —
 201.6

 Fixed Income Securities (a)

 —
 235.4
 —
 235.4

 8.9
 —
 —
 8.9

 —
 —
 $ 18.3
 18.3

 $ 251.3
 $ 334.5
 $ 18.3
 $ 604.1

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

 Activity in Level 3

 Balance as of December 31, 2023
 $ 18.9

 Actual Return on Plan Assets
 ( 0.6)

 Purchases, Sales, and Settlements – Net
 —

 Balance as of December 31, 2024
 $ 18.3

 Fair Value (Continued)

 Fair Value as of December 31, 2023

 Total

 Equity Securities:

 U.S. Large-cap (a)

 —
 $ 83.7
 —
 $ 83.7

 U.S. Mid-cap Growth (a)

 —
 69.9
 —
 69.9

 U.S. Small-cap (a)

 —
 46.5
 —
 46.5

 International
 $ 134.6
 —
 —
 134.6

 Fixed Income Securities (a)

 —
 215.0
 —
 215.0

 20.4
 —
 —
 20.4

 —
 —
 $ 18.9
 18.9

 $ 155.0
 $ 415.1
 $ 18.9
 $ 589.0

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

 Activity in Level 3

 Balance as of December 31, 2022
 $ 22.4

 Actual Return on Plan Assets
 ( 3.1)

 Purchases, Sales, and Settlements – Net
 ( 0.4)

 Balance as of December 31, 2023
 $ 18.9

 Postretirement Health and Life Fair Value

 Fair Value as of December 31, 2024

 Total

 Equity Securities: (a)

 U.S. Large-cap
 $ 32.1
 —
 —
 $ 32.1

 U.S. Mid-cap Growth
 30.0
 —
 —
 30.0

 U.S. Small-cap
 15.7
 —
 —
 15.7

 International
 37.9
 —
 —
 37.9

 Fixed Income Securities:

 Mutual Funds
 56.1
 —
 —
 56.1

 2.4
 —
 —
 2.4

 $ 174.2
 —
 —
 $ 174.2

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

 Fair Value (Continued)

 Fair Value as of December 31, 2023

 Total

 Equity Securities: (a)

 U.S. Large-cap
 $ 30.0
 —
 —
 $ 30.0

 U.S. Mid-cap Growth
 28.7
 —
 —
 28.7

 U.S. Small-cap
 14.9
 —
 —
 14.9

 International
 41.9
 —
 —
 41.9

 Fixed Income Securities:

 Mutual Funds
 55.1
 —
 —
 55.1

 3.2
 —
 —
 3.2

 $ 173.8
 —
 —
 $ 173.8

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

 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 $ 15.7 million in 2024 ($ 13.7 million in 2023; $ 12.0 million in 2022).

 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, 2024, 2023 and 2022.

 Stock-Based Compensation.

 Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, restricted stock units, stock appreciation rights and other awards. There are 0.7 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.5 million of these shares remain available for issuance as of December 31, 2024.

 The following types of share-based awards were outstanding in 2024, 2023 or 2022:

 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.

 NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
 Stock-Based Compensation (Continued)

 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

 2024
 2023
 2022

 Performance Shares
 $ 1.8
 $ 3.1
 $ 0.7

 Restricted Stock Units
 0.9
 0.8
 0.9

 Total Share-Based Compensation Expense
 $ 2.7
 $ 3.9
 $ 1.6

 Income Tax Benefit
 $ 0.8
 $ 1.1
 $ 0.5

 There were no capitalized share-based compensation costs during the years ended December 31, 2024, 2023 or 2022.

 As of December 31, 2024, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $ 3.3 million and $ 1.1 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years and 1.8 years, respectively.

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

 2024
 2023
 2022

 Weighted-
Average
 Weighted-
Average
 Weighted-
Average

 Non-vested as of January 1
 111,498
 $ 66.71
 60,489
 $ 69.62
 80,661
 $ 75.80

 Granted (a)

 88,927
 $ 64.33
 54,039
 $ 63.50
 37,731
 $ 67.22

 Awarded
 ( 46,725)
 $ 70.14
 —
 —
 —
 —

 Unearned Grant Award
 —
 —
 —
 —
 ( 50,524)
 $ 77.49

 Forfeited
 ( 12,099)
 $ 64.81
 ( 3,030)
 $ 67.60
 ( 7,379)
 $ 71.00

 Non-vested as of December 31
 141,601
 $ 64.24
 111,498
 $ 66.71
 60,489
 $ 69.62

 (a) Shares granted include accrued dividends.

 There were approximately 65,300 performance shares granted in January 2025 for the three -year performance period ending in 2027. 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 $ 4.6 million. There were approximately 14,200 performance shares awarded in February 2025. The grant date fair value of the shares awarded was $ 1.0 million.

 NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
 Stock-Based Compensation (Continued)

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

 2024
 2023
 2022

 Weighted- Average
 Weighted- Average
 Weighted- Average

 Available as of January 1
 43,744
 $ 62.38
 33,564
 $ 68.80
 28,141
 $ 73.16

 Granted (a)

 27,956
 $ 59.62
 21,200
 $ 61.16
 15,477
 $ 63.70

 Awarded
 ( 13,381)
 $ 63.80
 ( 9,631)
 $ 81.91
 ( 7,396)
 $ 75.55

 Forfeited
 ( 4,208)
 $ 60.21
 ( 1,389)
 $ 63.46
 ( 2,658)
 $ 66.44

 Available as of December 31
 54,111
 $ 60.77
 43,744
 $ 62.38
 33,564
 $ 68.80

 (a) Shares granted include accrued dividends.

 There were approximately 25,900 restricted stock units granted in January 2025 for the vesting period ending in 2027. The grant date fair value of the restricted stock units granted was $ 1.7 million. There were approximately 12,300 restricted stock units awarded in February 2025. The grant date fair value of the shares awarded was $ 0.8 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 net income attributable to ALLETE by each reportable 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.

 Management has identified that the Chief Operating Decision Maker (CODM) for the Company is not an individual, but rather the Executive Officers of ALLETE. These individuals represent various areas of the Company and provide direction for the allocation of resources. They interact with one another on a regular basis, with more formal meetings quarterly to discuss company strategy. The group is provided with monthly and quarterly financial materials that show net income attributable to ALLETE by segment with variances compared to the budget and prior year. No other measure of segment profit or loss is provided regularly to this group or used to assess performance and allocate resources. The group reviews the segment profit and loss taking into account the Company's goals and strategy, and provides direction for the allocation of resources.

 NOTE 14. BUSINESS SEGMENTS (Continued)

 2024
 2023
 2022

 Residential
 $ 177.0
 $ 165.7
 $ 175.9

 Commercial
 189.8
 184.6
 187.2

 Municipal
 34.2
 33.4
 40.2

 Industrial
 610.8
 593.6
 589.0

 Other Power Suppliers
 137.2
 146.1
 165.8

 Other
 93.7
 114.9
 101.2

 Total Regulated Operations
 1,242.7
 1,238.3
 1,259.3

 Long-term PSA
 56.4
 65.0
 77.2

 Sale of Wind Energy Facilities (a)

 22.9
 348.4
 33.5

 Other
 5.0
 5.1
 7.6

 Total ALLETE Clean Energy
 84.3
 418.5
 118.3

 Long-term Contract
 105.7
 101.2
 89.2

 Sale of Renewable Development Projects
 72.1
 92.5
 73.9

 Other
 25.0
 29.3
 30.0

 Total Corporate and Other
 202.8
 223.0
 193.1

 $ 1,529.8
 $ 1,879.8
 $ 1,570.7

 Net Income Attributable to ALLETE (b)

 $ 160.9
 $ 147.2
 $ 149.9

 ALLETE Clean Energy (c)

 17.8
 71.7
 16.3

 Corporate and Other (d)(e)

 0.6
 28.2
 23.1

 Total Net Income Attributable to ALLETE

 (a) Net income in 2023 includes the sales of ALLETE Clean Energy's Northern Wind and Red Barn projects.
 (b) Includes interest expense and interest income resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.
 (c) Net income in 2023 includes a $ 44.3 million after-tax gain recognized for a favorable arbitration ruling. (See Note 9. Commitments, Guarantees and Contingencies.)
 (d) 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.
 (e) Net income in 2024 includes transaction expenses of $ 22.6 million after-tax related to the Merger. (See Note 15. Agreement and Plan of Merger.)

 NOTE 14. BUSINESS SEGMENTS (Continued)

 Year Ended December 31, 2024
 Total Reportable Segments
 Corporate and Other / Eliminations
 Consolidated

 Contracts with Customers – Utility
 $ 1,242.7
 —
 $ 1,242.7
 —
 $ 1,242.7

 —
 $ 79.3
 79.3
 $ 202.8
 282.1

 Other – Non-utility
 —
 5.0
 5.0
 —
 5.0

 1,242.7
 84.3
 1,327.0
 202.8
 1,529.8

 Significant Segment Expenses:

 479.7
 —
 479.7

 64.6
 —
 64.6

 —
 18.3
 18.3

 250.0
 46.5
 296.5

 196.3
 57.5
 253.8

 52.5
 10.4
 62.9

 Other Segment Items (a)

 ( 38.7)
 66.2
 27.5

 Net Income (Loss) Attributable to ALLETE
 $ 160.9
 $ 17.8
 $ 178.7
 $ 0.6

 Other Segment Information:

 $ 196.3
 $ 57.5
 $ 253.8
 $ 17.7
 $ 271.5

 $( 66.1)
 $( 0.3)
 $( 66.4)
 $( 15.3)
 $( 81.7)

 $ 26.5
 —
 $ 26.5
 $( 1.5)
 $ 25.0

 Income Tax Benefit (Expense)
 $( 17.6)
 $ 15.6
 $( 2.0)
 $( 2.7)
 $( 4.7)

 Assets
 $ 4,489.4
 $ 1,477.4
 $ 5,966.8
 $ 787.5
 $ 6,754.3

 Equity Investment
 $ 194.4
 —
 $ 194.4
 $ 145.7
 $ 340.1

 Capital Expenditures
 $ 287.2
 $ 7.7
 $ 294.9
 $ 53.1
 $ 348.0

 (a) Other Segment Items consist of interest expense, equity earnings, AFUDC – Equity and income tax expense for Regulated Operations, and income tax benefit and net loss attributable to non-controlling interest for ALLETE Clean Energy.

 Year Ended December 31, 2023
 Total Reportable Segments
 Corporate and Other / Eliminations
 Consolidated

 Contracts with Customers – Utility
 $ 1,238.3
 —
 $ 1,238.3
 —
 $ 1,238.3

 —
 $ 413.4
 413.4
 $ 223.0
 636.4

 Other – Non-utility
 —
 5.1
 5.1
 —
 5.1

 1,238.3
 418.5
 1,656.8
 223.0
 1,879.8

 Significant Segment Expenses:

 484.3
 —
 484.3

 88.2
 —
 88.2

 —
 342.2
 342.2

 247.1
 52.1
 299.2

 179.2
 57.5
 236.7

 44.5
 10.0
 54.5

 Other Segment Items (a)

 ( 47.8)
 115.0
 67.2

 $ 147.2
 $ 71.7
 $ 218.9
 $ 28.2

 Other Segment Information:

 $ 179.2
 $ 57.5
 $ 236.7
 $ 15.1
 $ 251.8

 $( 63.9)
 $( 0.8)
 $( 64.7)
 $( 16.1)
 $( 80.8)

 $ 23.1
 —
 $ 23.1
 $( 1.4)
 $ 21.7

 Income Tax Expense
 $( 22.4)
 $( 2.7)
 $( 25.1)
 $( 2.8)
 $( 27.9)

 Assets
 $ 4,335.0
 $ 1,594.1
 $ 5,929.1
 $ 727.3
 $ 6,656.4

 Equity Investment
 $ 179.7
 —
 $ 179.7
 $ 151.5
 $ 331.2

 Capital Expenditures
 $ 236.3
 $( 5.3)
 $ 231.0
 $ 25.0
 $ 256.0

 (a) Other Segment Items consist of interest expense, equity earnings, AFUDC – Equity and income tax expense for Regulated Operations, and income tax expense, net loss attributable to non-controlling interest and gain recognized for a favorable arbitration ruling for ALLETE Clean Energy.

 NOTE 14. BUSINESS SEGMENTS (Continued)

 Year Ended December 31, 2022
 Total Reportable Segments
 Corporate and Other / Eliminations
 Consolidated

 Contracts with Customers – Utility
 $ 1,259.3
 —
 $ 1,259.3
 —
 $ 1,259.3

 —
 $ 110.7
 110.7
 $ 193.1
 303.8

 Other – Non-utility
 —
 7.6
 7.6
 —
 7.6

 1,259.3
 118.3
 1,377.6
 193.1
 1,570.7

 Significant Segment Expenses:

 545.5
 —
 545.5

 76.7
 —
 76.7

 —
 56.7
 56.7

 239.3
 47.3
 286.6

 171.9
 58.6
 230.5

 57.4
 10.7
 68.1

 Other Segment Items (a)

 ( 18.6)
 71.3
 52.7

 $ 149.9
 $ 16.3
 $ 166.2
 $ 23.1

 Other Segment Information:

 $ 171.9
 $ 58.6
 $ 230.5
 $ 11.7
 $ 242.2

 $( 58.1)
 $( 2.3)
 $( 60.4)
 $( 14.8)
 $( 75.2)

 $ 19.3
 —
 $ 19.3
 $( 0.6)
 $ 18.7

 Income Tax Benefit
 $ 10.4
 $ 15.4
 $ 25.8
 $ 5.4
 $ 31.2

 Assets
 $ 4,291.4
 $ 1,873.3
 $ 6,164.7
 $ 680.9
 $ 6,845.6

 Equity Investment
 $ 165.4
 —
 $ 165.4
 $ 157.3
 $ 322.7

 Capital Expenditures
 $ 158.3
 $ 2.2
 $ 160.5
 $ 47.6
 $ 208.1

 (a) Other Segment Items consist of interest expense, equity earnings, AFUDC – Equity and income tax benefit for Regulated Operations, and income tax benefit and net loss attributable to non-controlling interest for ALLETE Clean Energy.

 NOTE 15. AGREEMENT AND PLAN OF MERGER

 On May 5, 2024, ALLETE entered into the Merger Agreement. The Merger Agreement provides that, on the terms and subject to the conditions set forth therein, Alloy Merger Sub will merge with and into ALLETE, with ALLETE continuing as the surviving corporation in the Merger and becoming a subsidiary of Alloy Parent.

 Subject to the terms and conditions set forth in the Merger Agreement, which has been unanimously approved by the board of directors of ALLETE and approved and adopted by the shareholders of ALLETE, at the effective time of the Merger (Effective Time), each share of common stock, without par value, of ALLETE (ALLETE common stock) issued and outstanding immediately prior to the Effective Time (other than shares of ALLETE common stock held by any holder who properly exercises dissenters' rights under Minnesota law in respect of such shares and any shares of ALLETE common stock held by an affiliate of Alloy Parent) shall be converted into the right to receive $ 67.00 in cash, without interest (Merger Consideration). The aggregate equity value of the ALLETE common stock acquired by Parent will be approximately $ 3.9 billion as calculated as of May 5, 2024.

 NOTE 15. AGREEMENT AND PLAN OF MERGER (Continued)

 In addition, at the Effective Time, each restricted stock unit (RSU) with respect to ALLETE common stock subject to time-based vesting that is outstanding immediately prior to the Effective Time will be cancelled and converted into a contingent right to receive an amount in cash, without interest, equal to the Merger Consideration, payable (i) in the case of such right converted from unvested RSUs, upon the same vesting conditions as applied to the corresponding RSU or (ii) in the case of such right converted from vested RSUs, as soon as reasonably practicable following the closing date of the Merger (the Closing Date). Each performance share award with respect to ALLETE common stock that is outstanding and unvested immediately prior to the Effective Time and was issued prior to the execution of the Merger Agreement will be cancelled and converted into a right to receive, without interest, the Merger Consideration multiplied by the number of shares of ALLETE common stock subject to the award, determined based on attainment of the greater of target and actual performance as of the last business day immediately preceding the Closing Date. A pro rata portion (based on the elapsed portion of the performance period at that time) of these converted performance share awards will be paid out as soon as reasonably practicable following the Closing Date, with the remainder of the award being subject to time-vesting for the remainder of the applicable performance period. Performance share awards issued following the signing of the Merger Agreement will also be cancelled and converted into a contingent right to receive, without interest, the Merger Consideration multiplied by the number of shares of ALLETE common stock subject to the performance share award, determined at the target level of performance, and shall be subject to time-based vesting following the Merger. Further, purchase rights accumulated during the offering period in effect under the Company's ESPP immediately prior to closing will be automatically exercised into shares of ALLETE common stock no later than five business days prior to the Closing Date, and the ESPP will be terminated as of immediately prior to the Closing Date.

 Consummation of the Merger is subject to various closing conditions, including: (1) approval of the shareholders of ALLETE; (2) receipt of all required regulatory approvals without the imposition of a Burdensome Condition (as defined in the Merger Agreement); (3) absence of any law or order prohibiting the consummation of the Merger; (4) subject to materiality qualifiers, the accuracy of each party's representations and warranties; (5) each party's compliance in all material respects with its obligations and covenants under the Merger Agreement; and (6) the absence of a material adverse effect with respect to the Company. The Merger Agreement contains certain termination rights for ALLETE and Alloy Parent, which were described in a Current Report of Form 8-K filed by ALLETE on May 6, 2024. In the Merger Agreement, among other things, ALLETE has agreed, subject to certain exceptions, to, and to cause each of its subsidiaries to conduct its business in the ordinary course, consistent with past practice, from the date of the Merger Agreement until the Effective Time, and not to take certain actions prior to the closing of the Merger without the prior written consent of Alloy Parent (which consent shall not be unreasonably withheld, conditioned or delayed, except where ALLETE seeks Alloy Parent's consent to enter into a material new line of business or cease operations of an existing material line of business). The Merger Agreement also provides that ALLETE may notify Alloy Parent of our intent to raise equity capital of up to a total of $ 300 million in the second half of 2025, subject to certain parameters. If Alloy Parent declines to participate in the equity capital raises or fails to provide timely notice with respect thereto, ALLETE will have the right to issue ALLETE common stock in the public markets for an amount equal to any unfunded amounts under such equity capital raises.

 On July 10, 2024, ALLETE filed a definitive proxy statement relating to the special meeting of the shareholders held on August 21, 2024. At the special meeting, the shareholders of ALLETE voted to approve and adopt the Merger Agreement and approve the transactions contemplated thereby, including the Merger, among other matters.

 On July 19, 2024, ALLETE filed requests for approval of the Merger with the MPUC, PSCW and FERC. On October 7, 2024, the MPUC issued an order referring the docket to the Minnesota Office of Administrative Hearings for a contested case proceeding and requesting the Administrative Law Judge issue a report and recommendation by July 15, 2025. On January 23, 2025, a Stipulation of Facts and Waiver of Hearing was agreed to by all parties and submitted to the PSCW. SWL&P expects a PSCW ruling on the acquisition in the second quarter of 2025. ALLETE received approval from FERC on December 19, 2024. ALLETE also received approval from the Committee on Foreign Investment in the United States and all required international approvals in the third quarter of 2024. On January 31, 2025, ALLETE filed notification and report forms with the Antitrust Division of the Department of Justice and the Federal Trade Commission under the HSR Act. Approval of the Merger from these and other regulators, as well as expiration or early termination of any applicable waiting periods under the HSR Act, is required for consummation of the Merger.

 NOTE 16. 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

 2024

 $ 403.3
 $ 354.5
 $ 407.2
 $ 364.8

 $ 47.3
 $ 29.4
 $ 45.3
 $ 38.1

 $ 50.7
 $ 33.0
 $ 45.0
 $ 50.6

 Earnings Per Share of Common Stock

 Basic
 $ 0.88
 $ 0.57
 $ 0.78
 $ 0.88

 $ 0.88
 $ 0.57
 $ 0.78
 $ 0.87

 2023

 $ 564.9
 $ 533.4
 $ 378.8
 $ 402.7

 $ 48.3
 $ 53.5
 $ 36.0
 $ 43.1

 $ 58.2
 $ 51.5
 $ 85.9
 $ 51.5

 Earnings Per Share of Common Stock

 Basic
 $ 1.02
 $ 0.90
 $ 1.50
 $ 0.89

 $ 1.02
 $ 0.90
 $ 1.49
 $ 0.89

 2022

 $ 383.5
 $ 373.1
 $ 388.3
 $ 425.8

 $ 53.4
 $ 13.7
 $ 33.4
 $ 33.7

 $ 66.3
 $ 37.6
 $ 33.7
 $ 51.7

 Earnings Per Share of Common Stock

 Basic
 $ 1.24
 $ 0.67
 $ 0.59
 $ 0.90

 $ 1.24
 $ 0.67
 $ 0.59
 $ 0.90

 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

 Reserve Deducted from Related Assets

 Reserve For Uncollectible Accounts

 2022 Trade Accounts Receivable
 $ 1.8
 $ 1.9
 —
 $ 2.1
 $ 1.6

 2023 Trade Accounts Receivable
 $ 1.6
 $ 1.3
 —
 $ 1.3
 $ 1.6

 2024 Trade Accounts Receivable
 $ 1.6
 $ 1.4
 —
 $ 1.3
 $ 1.7

 Deferred Asset Valuation Allowance

 2022 Deferred Tax Assets
 $ 69.0
 $( 8.8)
 —
 —
 $ 60.2

 2023 Deferred Tax Assets
 $ 60.2
 $( 2.2)
 —
 —
 $ 58.0

 2024 Deferred Tax Assets
 $ 58.0
 $( 13.1)
 —
 —
 $ 44.9

 (a) Includes uncollectible accounts written-off.