United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)
	T	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the year ended December 31, 2018

£	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	Name of each exchange on which registered
Common Stock, without par value	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 x     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 x

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 x     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 and post such files).     Yes x     No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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. (Check one):     

Large Accelerated FilerxAccelerated 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes ¨     No x

The aggregate market value of voting stock held by nonaffiliates on June 29, 2018, was $3,959,298,983.

As of February 1, 2019, there were 51,519,442 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference

Portions of the Proxy Statement for the 2019 Annual Meeting of Shareholders are incorporated by reference in Part III.

Index

Definitions		4
Forward-Looking Statements		6
Part I		8
	Item 1. Business	8
	Regulated Operations	9
	Electric Sales / Customers	9
	Seasonality	12
	Power Supply	12
	Transmission and Distribution	14
	Investment in ATC	15
	Properties	15
	Regulatory Matters	15
	Regional Organizations	17
	Minnesota Legislation	17
	Competition	17
	Franchises	18
	Energy Infrastructure and Related Services	18
	ALLETE Clean Energy	18
	U.S. Water Services	19
	Corporate and Other	20
	BNI Energy	20
	Investment in Nobles 2	20
	ALLETE Properties	20
	Non-Rate Base Generation and Miscellaneous	21
	Environmental Matters	21
	Employees	21
	Availability of Information	22
	Executive Officers of the Registrant	22
	Item 1A. Risk Factors	23
	Item 1B. Unresolved Staff Comments	30
	Item 2. Properties	30
	Item 3. Legal Proceedings	31
	Item 4. Mine Safety Disclosures	31
Part II		31
	Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
	Item 6. Selected Financial Data	33
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Overview	34
	2018 Compared to 2017	35
	2017 Compared to 2016	39
	Critical Accounting Policies	43
	Outlook	45
	Liquidity and Capital Resources	52
	Capital Requirements	56
	Environmental and Other Matters	56
	Market Risk	56
	Recently Adopted Accounting Standards	57
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk	57
	Item 8. Financial Statements and Supplementary Data	58

ALLETE, Inc. 2018 Form 10-K

2

Index

	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58
	Item 9A. Controls and Procedures	58
	Item 9B. Other Information	58
Part III		59
	Item 10. Directors, Executive Officers and Corporate Governance	59
	Item 11. Executive Compensation	59
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	60
	Item 13. Certain Relationships and Related Transactions, and Director Independence	60
	Item 14. Principal Accounting Fees and Services	60
Part IV		61
	Item 15. Exhibits and Financial Statement Schedules	61
	Item 16. Form 10-K Summary	66
Signatures		67
Report of Independent Registered Public Accounting Firm		69
Consolidated Financial Statements - Audited		71
	Consolidated Balance Sheet	71
	Consolidated Statement of Income	72
	Consolidated Statement of Comprehensive Income	73
	Consolidated Statement of Cash Flows	74
	Consolidated Statement of Equity	75
	Notes to Consolidated Financial Statements	76
	Note 1. Operations and Significant Accounting Policies	76
	Note 2. Property, Plant and Equipment	88
	Note 3. Jointly-Owned Facilities and Projects	89
	Note 4. Regulatory Matters	89
	Note 5. Equity Investments	95
	Note 6. Acquisitions	96
	Note 7. Goodwill and Intangible Assets	97
	Note 8. Investments	98
	Note 9. Fair Value	99
	Note 10. Short-Term and Long-Term Debt	102
	Note 11. Commitments, Guarantees and Contingencies	104
	Note 12. Common Stock and Earnings Per Share	112
	Note 13. Income Tax Expense	113
	Note 14. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)	116
	Note 15. Pension and Other Postretirement Benefit Plans	116
	Note 16. Employee Stock and Incentive Plans	125
	Note 17. Business Segments	127
	Note 18. Quarterly Financial Data (Unaudited)	130
Schedule II		131

ALLETE, Inc. 2018 Form 10-K

3

Definitions

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

Abbreviation or Acronym	Term
AFUDC	Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
ALLETE	ALLETE, Inc.
ALLETE Clean Energy	ALLETE Clean Energy, Inc. and its subsidiaries
ALLETE Properties	ALLETE Properties, LLC and its subsidiaries
ALLETE South Wind	ALLETE South Wind, LLC
ALLETE Transmission Holdings	ALLETE Transmission Holdings, Inc.
ArcelorMittal	ArcelorMittal USA, Inc.
ASC	Accounting Standards Codification
ATC	American Transmission Company LLC
Basin	Basin Electric Power Cooperative
Bison	Bison Wind Energy Center
BNI Energy	BNI Energy, Inc. and its subsidiary
Boswell	Boswell Energy Center
Camp Ripley	Camp Ripley Solar Array
CIP	Conservation Improvement Program
Cliffs	Cleveland-Cliffs Inc.
CO2	Carbon Dioxide
Company	ALLETE, Inc. and its subsidiaries
DC	Direct Current
EIS	Environmental Impact Statement
EITE	Energy-Intensive Trade-Exposed
EPA	United States Environmental Protection Agency
ERP Iron Ore	ERP Iron Ore, LLC
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Form 8-K	ALLETE Current Report on Form 8-K
Form 10-K	ALLETE Annual Report on Form 10-K
Form 10-Q	ALLETE Quarterly Report on Form 10-Q
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gases
GNTL	Great Northern Transmission Line
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)
Laskin	Laskin Energy Center
Magnetation	Magnetation, LLC
Manitoba Hydro	Manitoba Hydro-Electric Board
MBtu	Million British thermal units

ALLETE, Inc. 2018 Form 10-K

4

Definitions (continued)

Abbreviation or Acronym	Term
Mesabi Metallics	Mesabi Metallics Company, LLC
Minnesota Power	An operating division of ALLETE, Inc.
Minnkota Power	Minnkota Power Cooperative, Inc.
MISO	Midcontinent Independent System Operator, Inc.
Montana-Dakota Utilities	Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.
Moody’s	Moody’s Investors Service, Inc.
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission
MW / MWh	Megawatt(s) / Megawatt-hour(s)
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
Nobles 2	Nobles 2 Power Partners, LLC
NOL	Net Operating Loss
NOX	Nitrogen Oxides
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
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
PolyMet	PolyMet Mining Corp.
PPA / PSA	Power Purchase Agreement / Power Sales Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCW	Public Service Commission of Wisconsin
RSOP	Retirement Savings and Stock Ownership Plan
SEC	Securities and Exchange Commission
S&P Global Ratings	Standard and Poor’s Global Ratings
Shell Energy	Shell Energy North America (US), L.P.
Silver Bay Power	Silver Bay Power Company, a wholly-owned subsidiary of Cliffs
SO2	Sulfur Dioxide
Square Butte	Square Butte Electric Cooperative, a North Dakota cooperative corporation
SWL&P	Superior Water, Light and Power Company
Taconite Harbor	Taconite Harbor Energy Center
Taconite Ridge	Taconite Ridge Energy Center
Tenaska	Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC
TCJA	Tax Cuts and Jobs Act of 2017 (Public Law 115-97)
Tonka Water	Tonka Equipment Company
Town Center District	Town Center at Palm Coast Community Development District in Florida
TransAlta	TransAlta Energy Marketing (U.S.) Inc.
United Taconite	United Taconite LLC, a wholly-owned subsidiary of Cliffs
UPM Blandin	UPM, Blandin paper mill owned by UPM-Kymmene Corporation
U.S.	United States of America
U.S. Water Services	U.S. Water Services, Inc. and its subsidiaries
USS Corporation	United States Steel Corporation
WTG	Wind Turbine Generator

ALLETE, Inc. 2018 Form 10-K

5

Forward-Looking Statements

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

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

• our ability to successfully implement our strategic objectives;

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

• changes in and compliance with laws and regulations;

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

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

• weather conditions, natural disasters and pandemic diseases;

• our ability to access capital markets and bank financing;

• 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 in regulated rates or sales price increases at our Energy Infrastructure and Related Services businesses;

• 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 Regulated Operations segment 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 not improve;

• the success of efforts to realize value from, invest in, and develop new opportunities in, our Energy Infrastructure and Related Services businesses;

• factors affecting our Energy Infrastructure and Related Services businesses, including fluctuations in the volume of customer orders, unanticipated cost increases, changes in legislation and regulations impacting the industries in which the customers served operate, the effects of weather, creditworthiness of customers, ability to obtain materials required to perform services, and changing market conditions; and

• our ability to successfully close the announced sale of U.S. Water Services, including the satisfaction of certain closing conditions, which cannot be assured to be completed.

ALLETE, Inc. 2018 Form 10-K

6

Forward Looking Statements (Continued)

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

ALLETE, Inc. 2018 Form 10-K

7

Part I

Item 1. Business

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 145,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 4. Regulatory Matters.)

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 545 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

U.S. Water Services provides integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency.

Corporate and Otheris comprised of BNI Energy, our coal mining operations in North Dakota, our investment in Nobles 2, ALLETE Properties, our legacy Florida real estate investment, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2018, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Year Ended December 31	2018			2017			2016
Consolidated Operating Revenue – Millions (a)		$1,498.6			$1,419.3			$1,339.7
Percentage of Consolidated Operating Revenue
Regulated Operations	71		%	75		%	75		%
ALLETE Clean Energy (a)	11		%	6		%	6		%
U.S. Water Services	11		%	11		%	10		%
Corporate and Other	7		%	8		%	9		%
	100		%	100		%	100		%

(a) Includes the sale of a wind energy facility to Montana-Dakota Utilities for $81.1 million in 2018.

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 17. Business Segments.

ALLETE, Inc. 2018 Form 10-K

8

REGULATED OPERATIONS

Electric Sales / Customers

Regulated Utility Kilowatt-hours Sold
Year Ended December 31	2018	%	2017	%	2016	%
Millions
Retail and Municipal
Residential	1,140	8	1,096	7	1,102	8
Commercial	1,426	10	1,420	10	1,442	10
Industrial	7,261	50	7,327	50	6,456	45
Municipal	798	5	799	5	816	6
Total Retail and Municipal	10,625	73	10,642	72	9,816	69
Other Power Suppliers	3,953	27	4,039	28	4,316	31
Total Regulated Utility Kilowatt-hours Sold	14,578	100	14,681	100	14,132	100

Industrial Customers. In 2018, industrial customers represented 50 percent of total regulated utility kWh sales. Our industrial customers are primarily in the taconite mining, iron concentrate, paper, pulp and secondary wood products, and pipeline industries.

Industrial Customer Kilowatt-hours Sold
Year Ended December 31	2018	%	2017	%	2016	%
Millions
Taconite/Iron Concentrate	5,039	69	4,930	67	3,906	61
Paper, Pulp and Secondary Wood Products	987	14	1,104	15	1,303	20
Pipelines and Other Industrial	1,235	17	1,293	18	1,247	19
Total Industrial Customer Kilowatt-hours Sold	7,261	100	7,327	100	6,456	100

Six taconite facilities served by Minnesota Power made up approximately 80 percent of 2017 iron ore pellet production in the U.S. according to data from the Minnesota Department of Revenue 2018 Mining Tax Guide. Sales to taconite customers and iron concentrate customers represented 5,039 million kWh, or 69 percent of total industrial customer kWh sales in 2018. 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. Iron concentrate reclamation facilities also use large quantities of electricity to extract and process iron-bearing tailings left from previous mining operations in the production of iron ore concentrate.

Minnesota Power’s taconite customers are capable of producing approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than 10 percent of Minnesota taconite production has been exported outside of North America. Minnesota Power also has provided electric service to three iron concentrate facilities capable of producing up to approximately 4 million tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets. These facilities have been idled since at least 2016. On July 17, 2018, ERP Iron Ore announced it would no longer seek to restart its iron concentrate operations. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 78 percent of capacity in 2018 (74 percent in 2017 and 71 percent in 2016). The World Steel Association, an association of over 160 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 2019 will increase by approximately one percent compared to 2018.

ALLETE, Inc. 2018 Form 10-K

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REGULATED OPERATIONS (Continued)

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)
2018*	38
2017	38
2016	28
2015	31
2014	39
2013	37
2012	39
2011	39
2010	35
2009	17
Source: Minnesota Department of Revenue 2018 Mining Tax Guide for years 2009 - 2017.
* Preliminary data from the Minnesota Department of Revenue.

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

In addition to serving the taconite industry, Minnesota Power serves a number of customers in the paper, pulp and secondary wood products industry, which represented 987 million kWh, or 14 percent of total industrial customer kWh sales in 2018. Minnesota Power also has agreements to provide steam for two of its paper and pulp customers for use in the customers’ operations. The four major paper and pulp mills we serve reported operating at lower levels in 2018 compared to 2017 resulting from the closure of the smaller of UPM Blandin’s two paper machines in the fourth quarter of 2017. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Industrial Customers and Prospective Additional Load.)

Large Power Customer Contracts. Minnesota Power has eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. The customers consist of six taconite facilities and four paper and pulp mills. Certain facilities have common ownership and are served under combined contracts.

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 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.

ALLETE, Inc. 2018 Form 10-K

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REGULATED OPERATIONS (Continued)

Large Power Customer Contracts (Continued)

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 minimize 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 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, 2018

Customer	Industry	Location	Ownership	Earliest Termination Date
ArcelorMittal – Minorca Mine	Taconite	Virginia, MN	ArcelorMittal S.A.	December 31, 2025
Hibbing Taconite Co. (a)	Taconite	Hibbing, MN	62.3% ArcelorMittal S.A. 23.0% Cliffs 14.7% USS Corporation	December 31, 2022
United Taconite and Northshore Mining	Taconite	Eveleth, MN and Babbitt, MN	Cliffs	December 31, 2026
USS Corporation (USS – Minnesota Ore) (a)(b)	Taconite	Mt. Iron, MN and Keewatin, MN	USS Corporation	December 31, 2022
Boise, Inc.	Paper	International Falls, MN	Packaging Corporation of America	December 31, 2023
UPM Blandin (c)(d)	Paper	Grand Rapids, MN	UPM-Kymmene Corporation	December 31, 2029
Verso Duluth Mill (e)	Paper and Pulp	Duluth, MN	Verso Corporation	December 31, 2024
Sappi Cloquet LLC (a)	Paper and Pulp	Cloquet, MN	Sappi Limited	December 31, 2022

(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, 2022.

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

(c) The smaller of UPM Blandin’s two paper machines was closed in the fourth quarter of 2017. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)

(d) Minnesota Power amended and extended its electric service agreement with UPM Blandin through 2029, subject to MPUC approval.

(e) Minnesota Power amended and extended its electric service agreement with Verso Corporation through 2024, which was approved by the MPUC at a hearing on December 20, 2018.

Residential and Commercial Customers. In 2018, residential and commercial customers represented 18 percent of total regulated utility kWh sales.

Municipal Customers. In 2018, municipal customers represented five percent of total regulated utility kWh sales. All of the municipal contracts include a termination clause requiring a three-year notice to terminate.

Minnesota Power’s wholesale electric contracts with 16 non-affiliated municipal customers in Minnesota have termination dates ranging from 2019 through at least 2032, with a majority of contracts effective through at least 2024. One municipal customer provided a contract termination notice in 2016, with the termination to be effective June 30, 2019. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. (See Note 4. Regulatory Matters.)

ALLETE, Inc. 2018 Form 10-K

11

REGULATED OPERATIONS (Continued)

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 11. Commitments, Guarantees and Contingencies, with additional disclosure provided in the following paragraphs.

Basin PSAs. Minnesota Power has an agreement to sell 100 MW of capacity and energy to Basin for a ten-year period which expires in April 2020. The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on the cost of fuel. The agreement also allows Minnesota Power to recover a pro rata share of increased costs related to emissions that occur during the last five years of the contract. Minnesota Power has three additional agreements to sell capacity to Basin at fixed prices. (See Note 11. Commitments, Guarantees and Commitments.)

Minnkota Power PSA. Minnesota Power has a PSA with Minnkota Power where Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold approximately 28 percent to Minnkota Power in 2018 (28 percent in 2017 and in 2016). (See Power Supply – Long-Term Purchased Power.)

Silver Bay Power PSA. In 2016, Minnesota Power and Silver Bay Power entered into a PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which has been served predominately through self-generation by Silver Bay Power. Through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power has the option to purchase additional energy from Minnesota Power as it transitions away from self-generation. By December 31, 2019, Silver Bay Power is expected to cease self-generation and Minnesota Power is expected to supply the energy requirements for Silver Bay Power.

Seasonality

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

Power Supply

In order to meet its customers’ electric requirements, Minnesota Power utilizes a mix of its own generation and purchased power. As of December 31, 2018, Minnesota Power’s generating capability is primarily coal-fired, but also includes wind energy, hydroelectric, natural gas-fired, biomass co-fired and solar generation. Purchased power primarily consists of long-term coal, wind and hydro PPAs as well as market purchases. The following table reflects Minnesota Power’s generating capabilities as of December 31, 2018, and total electrical supply for 2018. Minnesota Power had an annual net peak load of 1,589 MW on August 13, 2018.

ALLETE, Inc. 2018 Form 10-K

12

REGULATED OPERATIONS (Continued)

Power Supply (Continued)

					Year Ended
	Unit	Year	Net		December 31, 2018
Regulated Utility Power Supply	No.	Installed	Capability		Generation and Purchases
			MW		MWh	%
Coal-Fired
Boswell Energy Center	1	1958	67	(a)
in Cohasset, MN	2	1960	68	(a)
	3	1973	355
	4	1980	468	(b)
			958		6,442,894	42.9
Taconite Harbor Energy Center	1	1957	75
in Schroeder, MN	2	1957	75
			150	(c)	—	—
Total Coal-Fired			1,108		6,442,894	42.9
Biomass Co-Fired / Natural Gas
Hibbard Renewable Energy Center in Duluth, MN	3 & 4	1949, 1951	62		10,286	0.1
Laskin Energy Center in Hoyt Lakes, MN	1 & 2	1953	110		13,893	0.1
Total Biomass Co-Fired / Natural Gas			172		24,179	0.2
Hydro (d)
Group consisting of ten stations in MN	Multiple	Multiple	120		607,664	4.0
Wind (e)
Taconite Ridge Energy Center in Mt. Iron, MN	Multiple	2008	25		50,813	0.3
Bison Wind Energy Center in Oliver and Morton Counties, ND	Multiple	2010-2014	497		1,496,131	10.0
Total Wind			522		1,546,944	10.3
Solar
Camp Ripley Solar Array near Little Falls, MN	Multiple	2016	10		16,744	0.1
Total Generation			1,932		8,638,425	57.5
Long-Term Purchased Power
Lignite Coal - Square Butte near Center, ND (f)					1,717,616	11.4
Wind - Oliver County, ND					295,101	2.0
Hydro - Manitoba Hydro in Manitoba, Canada					292,148	1.9
Total Long-Term Purchased Power					2,304,865	15.3
Other Purchased Power (g)					4,087,176	27.2
Total Purchased Power					6,392,041	42.5
Total Regulated Utility Power Supply			1,932		15,030,466	100.0

(a) Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

(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 Projects.)

(c) Taconite Harbor Units 1 and 2 were idled in 2016. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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

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

(f) 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.)

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

ALLETE, Inc. 2018 Form 10-K

13

REGULATED OPERATIONS (Continued)

Power Supply (Continued)

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin region located in Montana and Wyoming. Coal consumption in 2018 for electric generation at Minnesota Power’s coal-fired generating stations was 3.8 million tons (3.8 million tons in 2017; 4.2 million tons in 2016). As of December 31, 2018, Minnesota Power had coal inventories of 0.9 million tons (1.2 million tons as of December 31, 2017). Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2019 and a portion of its coal requirements through December 2021. In 2019, 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 2021. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Coal Delivered to Minnesota Power
Year Ended December 31	2018		2017		2016
Average Price per Ton		$38.89		$36.50		$35.87
Average Price per MBtu		$2.10		$2.01		$1.98

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 11. 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 11. 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 2018 was approximately $1.60 per MBtu ($1.71 per MBtu in 2017; $1.57 per MBtu in 2016). (See Electric Sales / Customers – Minnkota Power PSA.)

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 345 kV (242 miles), 250 kV (465 miles), 230 kV (717 miles), 161 kV (43 miles), 138 kV (190 miles), 115 kV (1,285 miles) and less than 115 kV (6,342 miles). We own and operate 159 substations with a total capacity of 8,531 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

Great Northern Transmission Line. As a condition of a 250 MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power is constructing 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 a 2016 order, the MPUC approved the route permit for the GNTL, and in 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.‑Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre‑construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installation and transmission tower construction have commenced. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $380.8 million have been incurred through December 31, 2018, of which $203.7 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. (See Note 11. Commitments, Guarantees and Contingencies.)

ALLETE, Inc. 2018 Form 10-K

14

REGULATED OPERATIONS (Continued)

Investment in ATC

Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of December 31, 2018, our equity investment in ATC was $128.1 million ($118.7 million as of December 31, 2017). (See Note 5. Equity Investments.)

ATC’s authorized return on equity is 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In 2016, a federal administrative law judge ruled on a complaint proposing a reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending.

ATC’s 10-year transmission assessment, which covers the years 2018 through 2027, identifies a need for between $2.8 billion and $3.4 billion in transmission system investments. These investments by ATC, if undertaken, are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC.

Properties

Our Regulated Operations businesses own office and service buildings, an energy control center, repair shops, electric plants, transmission facilities and storerooms in various localities in Minnesota, Wisconsin and North Dakota. All of the electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. Most of the generating plants and substations are located on real property owned by Minnesota Power or SWL&P, subject to the lien of a mortgage, whereas most of the electric 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 Projects.)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities and other organizations.

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 programexpenditures 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. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments.

ALLETE, Inc. 2018 Form 10-K

15

REGULATED OPERATIONS (Continued)

Regulatory Matters (Continued)

2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC which sought an average increase of approximately 9 percent for retail customers. The rate filing sought a return on equity of 10.25 percent and a 53.81 percent equity ratio. The MPUC issued an order dated March 12, 2018, in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which is expected to result in additional revenue of approximately $13 million on an annualized basis. Interim rates were collected from January 1, 2017, through November 30, 2018, which were fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund, net of discounts provided to EITE customers, of $40.0 million as of December 31, 2018 ($23.7 million as of December 31, 2017) which is expected to be refunded in 2019. The MPUC also disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC also extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million pre-tax in the fourth quarter of 2017.

On April 2, 2018, Minnesota Power filed a petition with the MPUC requesting reconsideration of certain decisions in the MPUC’s order dated March 12, 2018. In an order dated May 29, 2018, the MPUC denied Minnesota Power’s petition for reconsideration and accepted a Minnesota Department of Commerce request for reconsideration reducing the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 while utilizing the benefits of the lower federal income tax rate enacted as part of the TCJA to mitigate the impact on customer rates.

Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 establishing a Minnesota energy policy to have competitive rates for certain industries such as mining and forest products. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an April 2017 order. Minnesota Power expects the discount to EITE customers to be approximately $16 million annually based on EITE customer current operating levels. While interim rates were in effect for Minnesota Power’s 2016 general rate case, discounts provided to EITE customers offset interim rate refund reserves for non-EITE customers. Minnesota Power provided $16.7 million of discounts to EITE customers during the year ended December 31, 2018 ($8.6 million and none for the years ended December 31, 2017, and 2016, respectively)

Additional regulatory proceedings pending with the MPUC are detailed in Note 4. Regulatory Matters.

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.

2016 Wisconsin General Rate Case.SWL&P’s retail rates in 2018 were based on a 2017 PSCW retail rate order effective August 2017 that allowed for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 2017 were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity.

2018 Wisconsin General Rate Case. On May 25, 2018, SWL&P filed a rate increase request with the PSCW requesting an average increase of 2.7 percent for retail customers (2.0 percent increase in electric rates; 2.3 percent increase in natural gas rates; and 0.1 percent increase in water rates). The filing sought an overall return on equity of 10.5 percent and a 55.41 percent equity ratio. In an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return on equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of approximately $1.3 million on an annualized basis.

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

Federal Energy Regulatory Commission. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for transmission of electricity in interstate commerce, electricity sold at wholesale (including the rates for Minnesota Power’s municipal and wholesale customers), natural gas transportation, certain accounting and record‑keeping practices, certain activities of our regulated utilities and the operations of ATC. FERC jurisdiction also includes enforcement of NERC mandatory electric reliability standards. Violations of FERC rules are subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation. Regulatory proceedings pending with the FERC are detailed in Note 4. Regulatory Matters.

ALLETE, Inc. 2018 Form 10-K

16

REGULATED OPERATIONS (Continued)

Regional Organizations

Midcontinent Independent System Operator, Inc. Minnesota Power, SWL&P and ATC are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, their transmission networks are under the regional operational control of MISO. Minnesota Power and SWL&P take and provide transmission service under the MISO open access transmission tariff. In cooperation with stakeholders, MISO manages the delivery of electric power across all or parts of 15 states and the Canadian province of Manitoba which includes nearly 200,000 MW of generating capacity.

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 seven regional entities that establish requirements, approved by the FERC, for reliable operation and maintenance of power generation facilities and transmission systems. Minnesota Power is subject to these reliability requirements and can incur significant penalties for non‑compliance.

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

The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, and all or parts of 16 states. The region includes more than 200 organizations that are involved in the production and delivery of electricity. These organizations include municipal utilities, cooperatives, investor-owned utilities, transmission system operators, a federal power marketing agency, Canadian Crown corporations and independent power producers.

Minnesota Legislation

Renewable Energy. Minnesota law requires 25 percent of electric utilities’ applicable retail and municipal energy sales in Minnesota to be from renewable energy sources by 2025. Minnesota law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power’s 2015 IRP, which was filed with the MPUC in 2015 and approved with modifications by the MPUC in a 2016 order, includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

Minnesota Power continues to execute its renewable energy strategy through renewable projects that will ensure it meets the identified state mandate at the lowest cost for customers. Minnesota Power has exceeded the interim milestone requirements to date with 26 percent of its applicable retail and municipal energy sales supplied by renewable energy sources in 2018.

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 by the end of 2020. 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. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

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 serves 10 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. 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.

ALLETE, Inc. 2018 Form 10-K

17

REGULATED OPERATIONS (Continued)

Competition (Continued)

In 2018, five percent of total regulated utility kWh sales were to municipal customers in Minnesota by contract. 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 at least December 31, 2032. Minnesota Power wholesale electric contracts with 14 municipal customers are effective through varying dates ranging from 2024 through 2029. In 2016, one of Minnesota Power’s municipal customers provided a contract termination notice effective June 30, 2019. (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 91 cities. The remaining cities, villages and towns served by Minnesota Power do not require a franchise to operate. SWL&P serves customers under electric, natural gas or water franchises in 1 city and 14 villages or towns.

ENERGY INFRASTRUCTURE AND RELATED SERVICES

ALLETE Clean Energy

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 545 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

ALLETE Clean Energy believes the market for renewable energy in North America is robust, driven by several factors including environmental regulation, tax incentives, societal expectations and continual technology advances. State renewable portfolio standards, and state or federal regulations to limit GHG emissions 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 and production tax credit requalification of existing facilities.

In January 2017, ALLETE Clean Energy announced that it would develop a wind energy facility of up to 50 MW to be sold to Montana-Dakota Utilities; sale of the wind energy facility was completed on October 31, 2018, with revenue of $81.1 million and cost of sales of $67.4 million recognized in the fourth quarter of 2018. ALLETE Clean Energy also constructed and sold a 107 MW wind energy facility to Montana-Dakota Utilities in 2015.

In March 2017, ALLETE Clean Energy announced it will build, own and operate a 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction is expected to be completed in late 2019. On March 15, 2018, ALLETE Clean Energy announced that it will build, own and operate an 80 MW wind energy facility pursuant to a 15-year PSA with NorthWestern Corporation; construction is expected to be completed in late 2019.

ALLETE, Inc. 2018 Form 10-K

18

ENERGY INFRASTRUCTURE AND RELATED SERVICES (Continued)

ALLETE Clean Energy (Continued)

ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current portfolio of approximately 545 MW 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. The current mix of PSA expiration and geographic location for existing facilities is as follows:

Wind Energy Facility	Location	Capacity MW	PSA MW	PSA Expiration
Armenia Mountain	Pennsylvania	100.5	100%	2024
Chanarambie/Viking	Minnesota	97.5
PSA 1 (a)			12%	2023
PSA 2			88%	2023
Condon	Oregon	50	100%	2022
Lake Benton	Minnesota	104	100%	2028
Lincoln Heights	Minnesota	8.8	100%	2028
Storm Lake I	Iowa	108	100%	2019
Storm Lake II	Iowa	77
PSA 1			90%	2019
PSA 2			10%	2032

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

The majority of ALLETE Clean Energy’s wind operations are located on real property owned by others with appropriate easement rights or necessary consents of governmental authorities. Two of ALLETE Clean Energy’s wind energy facilities are encumbered by liens against their assets securing financing. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Energy Infrastructure and Related Services – ALLETE Clean Energy.)

U.S. Water Services

On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million, subject to adjustment at closing, such as for changes in working capital. The transaction is expected to close by the end of the first quarter of 2019 upon receipt of regulatory approval. ALLETE plans to use the proceeds from the sale of U.S. Water Services primarily to reinvest in growth initiatives at our Regulated Operations and ALLETE Clean Energy. ALLETE will also consider using a portion of the proceeds to implement a common stock repurchase program.

U.S. Water Services provides integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. U.S. Water Services has a presence in 49 states and Canada and has an established base of approximately 4,900 customers. U.S. Water Services differentiates itself from the competition by developing synergies between solutions in engineering, equipment and chemical water treatment, which helps customers achieve efficient and sustainable use of their water and energy systems. U.S. Water Services is a leading provider to the biofuels industry, and also serves the commercial and institutional markets, food and beverage, light manufacturing, power generation, and midstream oil and gas industries, among others. U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. U.S. Water Services sells certain products which are seasonal in nature, with higher demand typically realized in warmer months; generally, lower sales occur in the first quarter of each year. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Energy Infrastructure and Related Services – U.S. Water Services.)

In September 2017, U.S. Water Services acquired Tonka Water for total consideration of $19.2 million. Tonka Water is a supplier of municipal and industrial water treatment systems that expanded U.S. Water Services’ geographic and customer markets.

U.S. Water Services leases an office and production facility at its headquarters in Minnesota as well as various office, warehouse and production facilities across the United States.

ALLETE, Inc. 2018 Form 10-K

19

CORPORATE AND OTHER

BNI Energy

BNI Energy is a supplier of lignite coal in North Dakota, producing approximately 4 million tons annually and has an estimated 650 million tons of lignite coal reserves. Two electric generating cooperatives, Minnkota Power and Square Butte, consume virtually all of BNI Energy’s production of lignite under cost-plus fixed fee coal supply agreements extending through December 31, 2037. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 11. 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, 2018, BNI Energy had a $26.5 million asset reclamation obligation ($25.0 million as of December 31, 2017) included in Other Non-Current Liabilities on the Consolidated Balance Sheet. These costs are included in the cost-plus fixed fee contract, for which an asset reclamation cost receivable was included in Other Non-Current Assets on the Consolidated Balance Sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of credit. (See Note 11. Commitments, Guarantees and Contingencies.)

Investment in Nobles 2

On December 27, 2018, our wholly-owned subsidiary, ALLETE South Wind, entered into a partnership agreement with Tenaska to purchase a 49 percent equity interest in Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. The wind energy facility will be built in Nobles County, Minnesota and is expected to be completed in late 2020, with an estimated total project cost of approximately $350 million to $400 million of which our portion is expected to be approximately $170 million to $200 million. We expect to utilize tax equity to finance a portion of our project costs, with an ALLETE expected equity investment of approximately $60 million to $70 million. We account for our investment in Nobles 2 under the equity method of accounting. As of December 31, 2018, our equity investment in Nobles 2 was $33.0 million. (See Note 5. Equity Investments.)

ALLETE Properties

ALLETE Properties represents our legacy Florida real estate investment. ALLETE Properties’ major projects in Florida are Town Center at Palm Coast and Palm Coast Park.

Summary of Projects		Residential	Non-residential
As of December 31, 2018	Acres (a)	Units (b)	Sq. Ft. (b)(c)
Projects
Town Center at Palm Coast	962	2,419	2,022,700
Palm Coast Park	638	—	1,181,000
Total Projects	1,600	2,419	3,203,700

(a) Acreage amounts are approximate and shown on a gross basis, including wetlands.

(b) Units and square footage are estimated. Density at build out may differ from these estimates.

(c) Includes retail and non-retail commercial, office, industrial, warehouse, storage and institutional square footage.

In addition to the two projects, ALLETE Properties has approximately 600 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 certain qualified buyers. As of December 31, 2018, outstanding finance receivables were $15.1 million, net of reserves, with maturities through 2022. 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.

ALLETE, Inc. 2018 Form 10-K

20

CORPORATE AND OTHER (Continued)

Non-Rate Base Generation and Miscellaneous

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

As of December 31, 2018, non-rate base generationconsists of 29 MW of generation at Rapids Energy Center. In 2018, we sold 0.1 million MWh of non-rate base generation (0.1 million MWh in 2017 and in 2016).

Non-Rate Base Power Supply	Unit No.	Year Installed	Year Acquired	Net Capability (MW)
Rapids Energy Center (a)
in Grand Rapids, MN
Steam – Biomass (b)	6 & 7	1969, 1980	2000	27
Hydro	4 & 5	1917, 1948	2000	2

(a) The net generation is primarily dedicated to the needs of one customer, UPM Blandin in Grand Rapids, Minnesota. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)

(b) The fuel supply for Rapids Energy Center Units 6 and 7 is supplemented by coal, but in 2019, those units will operate on natural gas.

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 11. Commitments, Guarantees and Contingencies.)

EMPLOYEES

As of December 31, 2018, ALLETE had 1,889 employees, of which 1,852 were full-time.

Minnesota Power and SWL&P have an aggregate of 475 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The current labor agreements with IBEW Local 31 expire on April 30, 2020, for Minnesota Power and February 1, 2021, for SWL&P.

BNI Energy has 181 employees, of which 139 are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2019.

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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.

EXECUTIVE OFFICERS OF THE REGISTRANT

As of February 14, 2019, these are the executive officers of ALLETE:

Executive Officers	Initial Effective Date
Alan R. Hodnik, Age 59
Chairman and Chief Executive Officer (a)	January 31, 2019
Chairman, President and Chief Executive Officer	May 10, 2011
President and Chief Executive Officer	May 1, 2010
Bethany M. Owen, Age 53
President (a)	January 31, 2019
Senior Vice President and Chief Legal and Administrative Officer	November 26, 2016
Robert J. Adams, Age 56
Senior Vice President and Chief Financial Officer	March 4, 2017
Senior Vice President – Energy-Centric Businesses and Chief Risk Officer	November 14, 2015
Vice President – Energy-Centric Businesses and Chief Risk Officer	June 23, 2014
Vice President – Business Development and Chief Risk Officer	May 13, 2008
Patrick L. Cutshall, Age 53
Vice President and Corporate Treasurer	December 18, 2017
Treasurer	January 1, 2016
Steven W. Morris, Age 57
Vice President, Controller and Chief Accounting Officer	December 24, 2016
Controller	March 3, 2014
Patrick K. Mullen, Age 58 (b)
Senior Vice President – External Affairs	April 10, 2017
Bradley W. Oachs, Age 61
Senior Vice President and President – Regulated Operations	November 26, 2016
Margaret A. Thickens, Age 52
Vice President, Chief Legal Officer and Corporate Secretary	February 13, 2019

(a) On January 31, 2019, the Board of Directors of ALLETE appointed Bethany M. Owen as President of ALLETE.

(b) On January 14, 2019, Mr. Mullen announced his plan to retire. As part of an orderly transition, it is expected that Mr. Mullen will remain with the Company until some time in the second quarter of 2019.

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EXECUTIVE OFFICERS OF THE REGISTRANT (Continued)

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

Mr. Cutshall was Director – Investments and Tax; Director – Investments.

Mr. Morris was Director – Accounting.

Mr. Mullen was Vice President – Marketing and Corporate Communications.

Mr. Oachs was Chief Operating Officer – Minnesota Power.

Ms. Owen was Vice President – Information Technology Solutions and President – SWL&P.

Ms. Thickens was General Counsel and Director of Compliance – ALLETE Clean Energy; General Counsel and Secretary – ALLETE Clean Energy; Attorney Senior.

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 14, 2019.

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.

Certain of these risk factors below relate to U.S. Water Services. On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million, subject to adjustment at closing, such as for changes in working capital. The transaction is expected to close by the end of the first quarter of 2019. Risk factors relating to U.S. Water Services exist up to the closing of the sale, or in the future should the sale not be consummated.

Entity-wide Risks

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

We rely on access to financing sources and the capital markets, on acceptable terms and at reasonable costs, as sources of liquidity for capital requirements not satisfied by our cash flows from operations. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access and financing costs in the capital markets.  Such disruptions or causes of a downgrade could include but are not limited to: the effects of the TCJA on the Company’s cash flow metrics; a loss of, or a reduction in sales to, Large Power 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 our Energy Infrastructure and Related Services businesses as compared to that from our Regulated Operations; deteriorating economic or capital market conditions; or volatility in commodity prices.  

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

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

A deterioration in general economic conditions may have adverse impacts on our financial position, results of operations and cash flows.

If economic conditions deteriorate on a national or regional level, it may have a negative impact on the Company’s financial position, results of operations and cash flows as well as on our customers. This impact may include volatility and unpredictability in the demand for the products and services offered by our businesses, the loss of existing customers, tempered growth strategies, production cutbacks or customer bankruptcies. 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.

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

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

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

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

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

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

We are exposed to significant reputational risk.

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

Catastrophic events, such as natural disasters and acts of war, may adversely affect our operations.

Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, 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 such events, these measures may not be successful. Furthermore, despite these measures, if such an occurrence were to occur, our financial position, results of operations and cash flows could be adversely affected.

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Item 1A. Risk Factors (Continued)

Entity-wide Risks (Continued)

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, provide integrated water management at U.S. Water Services, 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 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. Computer viruses, terrorism, theft and sabotage could impact our systems and facilities, or those of third parties on which we rely, which may disrupt our operations.

Our businesses require the continued operation of sophisticated 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 and 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.

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

We are required to make judgments in order to estimate federal and state tax obligations. These judgments include reserves for potential adverse outcomes for tax positions that may be challenged by tax 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 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, our financial position, results of operations and cash flows may be adversely impacted.

Regulated Operations Risks

Our results of operations could be negatively impacted if our Large Power Customers experience an economic downturn,incurwork stoppages, fail to compete effectively, experience decreased demand or experience a decline in prices for their product.

Minnesota Power’s eight Large Power Customers accounted for 24 percent of our 2018 consolidated operating revenue (25 percent in 2017 and 22 percent in 2016), of which one of these customers accounted for approximately 10 percent of consolidated revenue in 2018 (10 percent in 2017 and 8 percent in 2016). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the marketplace. Additionally, the North American paper and pulp industry also faces declining demand due to the impact of electronic substitution for print and changing customer needs.

Accordingly, if our customers experience an economic downturn, incur a work stoppage (including strikes, lock-outs or other events), fail to compete effectively, experience decreased demand or experience a decline in prices for their product, there could be adverse effects on their operations and, consequently, this could have a negative impact on our results of operations if we are unable to remarket at similar prices the energy that would otherwise have been sold to such Large Power Customers.

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

Our utility operations 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.

We are subject to an extensive legal and regulatory framework imposed under federal and state law including regulations administered by the FERC, MPUC, MPCA, PSCW, NDPSC and EPA as well as regulations administered by other organizations including the NERC. These laws and regulations relate to allowed rates of return, capital structure, financings, rate and cost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and distribution facilities (including the ongoing maintenance and reliable operation of such facilities), recovery of purchased power costs and capital investments, approval of integrated resource plans and present or prospective wholesale and retail competition, renewable portfolio standards that require utilities to obtain specified percentages of electric supply from eligible renewable generation sources, among other things. Energy policy initiatives at the state or federal level could increase renewable portfolio standards or incentives for distributed generation, municipal utility ownership, or local initiatives could introduce generation or distribution requirements that could change the current integrated utility model. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. Compliance with these standards may lead to increased operating costs and capital expenditures. 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 or the adoption of new regulations could have an adverse impact on our results of operations.

Our ability to obtain rate adjustments to maintain reasonable rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or reasonable authorized rates of return on capital will be earned. Minnesota Power and SWL&P, from time to time, file general rate cases with, or otherwise seek cost recovery authorization from, federal and state regulatory authorities. If Minnesota Power and SWL&P do not receive an adequate amount of rate relief in general rate cases, including if rates are reduced, if increased rates are not approved on a timely basis, if cost recovery is 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 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 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 can result in increased capital expenditures, environmental emission allowance trading, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to emissions at generating facilities, coal ash, water discharge and wind energy 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.

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.

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

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.

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

There is significant uncertainty regarding if and when new laws or regulations will be adopted to reduce GHG and the impact any such laws or regulations would have on us. In 2018, coal was the primary fuel source for 75 percent of the energy produced by our generating facilities. Any future limits on GHG emissions at the federal or state level may require us to incur significant capital expenditures and increases in operating costs, which if significant, could result in the closure of certain coal-fired energy centers, an impairment of assets, or otherwise adversely affect our results of operations, particularly if such expenditures and costs are not fully recoverable from customers.

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

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

The operation of generating facilities involves many risks, including start-up operations risks, breakdown or failure of facilities, the dependence on a specific fuel source, inadequatefuel supply, availability of fuel transportation, and the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. A significant portion of our facilities contain older generating equipment, which, even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. Generation and transmission facilities and equipment are also likely to require periodic upgrades and improvements due to changing environmental standards and technological advances. We could be subject to costs associated with any unexpected failure to produce or deliver power, including failure caused by breakdown or forced outage, as well as repairing damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events.

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

We expect to incur significant capital expenditures in making capital 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 or not completed in a timely manner, we could be subject to additional costs or impairments which could have an adverse impact on our financial position, results of operation and cash flows.

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

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

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Item 1A. Risk Factors (Continued)

Regulated Operations Risks (Continued)

Our results of operations could be impacted by declining wholesale power prices.

Wholesale prices for electricity have declined in recent years primarily due to low natural gas prices. If there are reductions in demand from customers or if we lose customers, 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 the low wholesale prices for electricity, we can make no assurances that our power marketing efforts would fully offset any reduction in earnings resulting from the lower demand from existing customers or the loss of customers.

The price of electricity and fuel may be volatile.

Volatility in market prices for electricity and 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 transportation;

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

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

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

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. Volatility in market prices for our fuel and purchase power costs primarily impacts our sales to Other Power Suppliers.

Demand for energy may decrease.

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

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.

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

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Item 1A. Risk Factors (Continued)

Energy Infrastructure and Related Services Risks

The inability to successfully manage and grow our Energy Infrastructure and Related Services businesses could adversely affect our results of operations.

Our Energy Infrastructure and Related Services businesses consist of ALLETE Clean Energy and U.S. Water Services. The Company's strategy for these businesses includes adding customers, products, and new geographies, project development for others and growth through acquisitions. This strategy depends, in part, on the Company’s ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on acceptable terms. The Company may compete with other companies for these acquisition opportunities, which may increase the Company’s cost of making acquisitions and the Company may be unsuccessful in pursuing these acquisition opportunities. These 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. 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, products and geographies, it may impede our long-term objectives and business strategy.

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

U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. Some of these customers can be adversely affected by low commodity prices such as those for ethanol and oil which may cause these customers to purchase less of U.S. Water Services’ products and services. If U.S. Water Services is unable to retain its existing customers, add new customers, or if it experiences reduced demand for its products and services, adverse impacts on our results of operations could occur that would prevent us from achieving our future growth expectations.

The generation of electricity from ALLETE Clean Energy’s wind energy facilities depends heavily on suitable meteorological conditions.

ALLETE Clean Energy’s facilities are geographically diverse; however, if wind conditions are unfavorable, ALLETE Clean Energy’s electricity generation and revenue from its wind energy facilities may be substantially below its expectations. The electricity produced, production tax credits received, and revenues generated by a wind energy facility are highly dependent on suitable wind conditions and associated weather conditions, which are beyond ALLETE Clean Energy’s control. Furthermore, components of its systems could be damaged by severe weather, such as hailstorms, lightning or tornadoes. In addition, replacement and spare parts for key components of ALLETE Clean Energy’s diverse turbine portfolio may be difficult or costly to acquire or may be unavailable. Unfavorable weather and atmospheric conditions could impair the effectiveness of ALLETE Clean Energy’s assets or reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of its wind energy facilities.

The construction, operation and maintenance of ALLETE Clean Energy’s electric generation 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, start-up operations risks, breakdown or failure of facilities, 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. A portion of our facilities contain older generating equipment, 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 repairing damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events.

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Item 1A. Risk Factors (Continued)

Energy Infrastructure and Related Services Risks (Continued)

As contracts with its counterparties expire, ALLETE Clean Energy may not be able to replace them with agreements on similar terms.

ALLETE Clean Energy is party to PSAs which expire in various years between 2019 and 2032. 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, or sell energy in the wholesale market resulting in similar revenue, our financial position, results of operations and cash flows could be adversely affected.

Counterparties to ALLETE Clean Energy’s turbine supply, service and maintenance, or offtake agreements may not fulfill their obligations.

ALLETE Clean Energy is party to turbine 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 ALLETE Clean Energy is 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 and intangible assets. A determination that goodwill or intangible assets have been impaired could result in a significant non-cash charge to earnings.

We had approximately $223 million of goodwill and intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2018. If we change our business strategy, fail to deliver on our projected results or if market or other conditions adversely affect the operations of U.S. Water Services, we may be required to record an impairment charge. Declines in projected operating cash flows at U.S. Water Services 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.

Corporate and Other Risks

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. In addition, BNI Energy and its customers may be adversely impacted by environmental laws and regulations which could have an adverse effect on our financial position, results of operations and cash flows.

Real estate market conditions where our legacy Florida real estate investment is located may not improve.

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, continued 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

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Item 3. Legal Proceedings

Discussions of material regulatory and environmental proceedings are included in Note 4. Regulatory Matters and Note 11. 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.

Part II

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

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends, without interruption, on our common stock since 1948. A quarterly dividend of $0.5875 per share on our common stock is payable on March 1, 2019, to the shareholders of record on February 15, 2019. 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, 2019, there were approximately 22,000 common stock shareholders of record.

Performance Graph.

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

The calculations assume a $100 investment on December 31, 2013, and reinvestment of dividends.

ALLETE, Inc. 2018 Form 10-K

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

	2013	2014	2015	2016	2017	2018
ALLETE	$100	$115	$110	$144	$172	$182
S&P 500 Index	$100	$114	$115	$129	$157	$150
Philadelphia Utility Index	$100	$129	$121	$142	$160	$166

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Item 6. Selected Financial Data

	2018			2017			2016			2015			2014
Millions Except Per Share Amounts
Operating Revenue (a)		$1,498.6			$1,419.3			$1,339.7			$1,486.4			$1,136.8
Operating Expenses (a)		$1,297.4			$1,193.4			$1,122.7			$1,274.7			$946.9
Net Income (b)		$174.1			$172.2			$155.8			$141.5			$125.5
Less: Non-Controlling Interest in Subsidiaries(c)	—			—			0.5			0.4			0.7
Net Income Attributable to ALLETE (b)		$174.1			$172.2			$155.3			$141.1			$124.8
Common Stock Dividends	115.0			108.7			102.7			97.9			83.8
Earnings Retained in Business (b)		$59.1			$63.5			$52.6			$43.2			$41.0
Shares Outstanding
Year-End	51.5			51.1			49.6			49.1			45.9
Average (d)
Basic	51.3			50.8			49.3			48.3			42.9
Diluted	51.5			51.0			49.5			48.4			43.1
Diluted Earnings Per Share (b)		$3.38			$3.38			$3.14			$2.92			$2.90
Total Assets		$5,165.0			$5,080.0			$4,876.9			$4,864.4			$4,329.1
Long-Term Debt		$1,428.5			$1,439.2			$1,370.4			$1,556.7			$1,263.2
Return on Common Equity (b)	8.3		%	8.6		%	8.4		%	8.0		%	8.6		%
Common Equity Ratio	59		%	58		%	55		%	53		%	54		%
Dividends Declared per Common Share		$2.24			$2.14			$2.08			$2.02			$1.96
Dividend Payout Ratio (b)	66		%	63		%	66		%	69		%	68		%
Book Value Per Share at Year-End		$41.85			$40.46			$38.17			$37.18			$35.04
Capital Expenditures by Segment
Regulated Operations		$211.9			$177.1			$121.8			$224.4			$583.5
ALLETE Clean Energy	89.7			56.1			106.9			8.6			4.2
U.S. Water Services	5.0			4.4			3.7			2.9			—
Corporate and Other	12.0			28.9			15.4			15.9			16.6
Total Capital Expenditures		$318.6			$266.5			$247.8			$251.8			$604.3

(a) In 2015, operating revenue and operating expenses included $197.7 million and $162.9 million, respectively, for the sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities. In 2018, operating revenue and operating expenses included $81.1 million and $67.4 million, respectively, for the sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities.

(b) The year ended December 31, 2017, includes the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 13. Income Tax Expense.)

(c) The non-controlling interest related to ALLETE Clean Energy’s Condon wind energy facility was acquired in 2016. (See Note 6. Acquisitions.)

(d) Excludes unallocated ESOP shares in 2014.

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

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

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Overview

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

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 145,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 4. Regulatory Matters.)

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 545 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

U.S. Water Services provides integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency.

Corporate and Otheris comprised of BNI Energy, our coal mining operations in North Dakota, our investment in Nobles 2, ALLETE Properties, our legacy Florida real estate investment, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2018, 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.

2018 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2018, to the year ended December 31, 2017.

Net income attributable to ALLETE in 2018 was $174.1 million, or $3.38 per diluted share, compared to $172.2 million, or $3.38 per diluted share, in 2017. Net income in 2017 included the favorable impacts of $13.0 million after-tax, or $0.25 per share, for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA and $7.9 million after-tax, or $0.16 per share, related to the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits. Net income in 2017 also included a non‑cash $11.4 million after-tax charge, or $0.22 per share, for the MPUC’s decision in Minnesota Power’s 2016 general rate case disallowing recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs. (See Note 4. Regulatory Matters.) Earnings per share dilution in 2018 was $0.04 due to additional shares of common stock outstanding as of December 31, 2018.

Regulated Operations net income attributable to ALLETE was $131.0 million in 2018, compared to $128.4 million in 2017. Net income at Minnesota Power was higher than 2017 reflecting the non‑cash $11.4 million after-tax charge in 2017 for the MPUC’s decision in Minnesota Power’s 2016 general rate case disallowing recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs. Net income in 2018 included lower transmission revenue resulting from lower MISO-related revenue and a $3.1 million after-tax out-of-period adjustment for an estimated true-up of MISO rates that were billed in 2017 and are expected to be credited to customers in 2019, the timing of fuel adjustment clause recoveries, lower industrial sales, and higher property tax and interest expense. These decreases were partially offset by lower operating and maintenance expense, higher pricing on PSAs with Other Power Suppliers, increased cost recovery rider revenue, and higher sales to residential and commercial customers due to more favorable weather conditions in 2018. Net income in 2018 also included higher depreciation expense resulting from a reduction in the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035, which was offset by the benefits of the lower federal income tax rate enacted as part of the TCJA. Net income at SWL&P and our after-tax equity earnings in ATC were similar to 2017.

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2018 Financial Overview (Continued)

ALLETE Clean Energy net income attributable to ALLETE was $33.7 million in 2018 compared to $41.5 million in 2017. Net income in 2017 included a $23.6 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. Net income in 2018 included the sale of a wind energy facility to Montana-Dakota Utilities, a lower federal income tax rate enacted as part of the TCJA and $7.4 million after-tax of additional production tax credits generated as ALLETE Clean Energy continues to execute its refurbishment strategy. Of the $7.4 million after-tax in additional production tax credits, $3.0 million resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017. These increases were partially offset by higher operating and maintenance expenses.

U.S. Water Services net income attributable to ALLETE was $3.2 million in 2018, compared to $10.7 million in 2017. Net income in 2017 included a $9.2 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. Net income in 2018 included increased revenue primarily due to higher capital project sales and higher sales of chemicals and related services, partially offset by higher operating expenses. Net income in 2018 included $0.6 million of after-tax expense recognized as cost of sales related to purchase accounting for sales backlog.

Corporate and Other net income attributable to ALLETE was $6.2 million in 2018 compared to a net loss of $8.4 million in 2017. The net loss in 2017 included additional income tax expense of $19.8 million after-tax for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA and a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits. Net income in 2018 included an increase for the change in fair value of the contingent consideration liability of $1.3 million after-tax as compared to 2017.

2018 Compared to 2017

(See Note 17. Business Segments for financial results by segment.)

Regulated Operations

Year Ended December 31	2018			2017
Millions
Operating Revenue – Utility		$1,059.5			$1,063.8
Fuel, Purchased Power and Gas – Utility	407.5			396.9
Transmission Services – Utility	69.9			71.2
Operating and Maintenance	220.1			227.3
Depreciation and Amortization	158.0			132.6
Taxes Other than Income Taxes	52.5			51.1
Operating Income	151.5			184.7
Interest Expense	(60.2		)	(57.0		)
Equity Earnings in ATC	17.5			22.5
Other Income	6.7			5.4
Income Before Income Taxes	115.5			155.6
Income Tax Expense (Benefit)	(15.5		)	27.2
Net Income Attributable to ALLETE	$131.0				$128.4

Operating Revenue – Utilitydecreased$4.3 million from 2017 primarily due to lower transmission revenue, the impact of a regulatory outcome in 2017 related to the allocation of North Dakota investment tax credits, provision for tax reform refund related to income tax changes resulting from the TCJA, and lower financial incentives under the Minnesota conservation improvement program, partially offset by higher revenue from kWh sales, cost recovery rider revenue, fuel clause adjustment recoveries, and conservation improvement program recoveries.

Transmission revenue decreased $15.0 million primarily due to lower MISO-related revenue and a $4.4 million out-of-period adjustment for an estimated true-up of MISO rates that were billed in 2017 and are expected to be credited to customers in 2019.

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2018 Compared to 2017 (Continued)

Regulated Operations (Continued)

Revenue decreased $14.0 million due to the impact of a regulatory outcome in 2017 related to the allocation of North Dakota investment tax credits. This decrease in revenue was offset by the income tax impacts of the regulatory outcome resulting in no impact to net income for Regulated Operations. (See Note 4. Regulatory Matters and Income Tax Expense.)

Revenue decreased $11.9 million from 2017 reflecting income tax changes resulting from the TCJA primarily related to a provision for tax reform refund for the benefit of excess deferred income taxes in 2018. We have recorded the benefit of these excess deferred income taxes for Minnesota Power and SWL&P as regulatory liabilities. (See Note 4. Regulatory Matters.)

Financial incentives under the Minnesota conservation improvement program were lower by $2.5 million from 2017 as a result of MPUC-approved modifications to the mechanism for calculating the financial incentives.

Interim retail rates of $29.5 million collected in 2018 were fully offset by the recognition of a corresponding reserve throughout the year. In the fourth quarter of 2017, Minnesota Power recognized interim retail rate refund reserves of $31.6 million to fully offset interim retail rates collected throughout the year in 2017 due to the regulatory outcome of the MPUC’s decision in Minnesota Power’s 2016 general rate case at a hearing on January 18, 2018.

Revenue increased $13.5 million from 2017 reflecting higher kWh sales to Residential and Commercial customers, and higher pricing on sales to Other Power Suppliers. Sales to Residential and Commercial customers increased in 2018 primarily due to more favorable weather conditions in 2018 compared to 2017. Sales to Industrial customers decreased0.9 percent reflecting lower sales to UPM Blandin as a result of the closure of the smaller of its two paper machines in the fourth quarter of 2017 and Husky Energy due to an April 2018 fire at its refinery in Superior, Wisconsin, partially offset by increased taconite production. Revenue from Other Power Suppliers increased due to higher pricing on sales, partially offset by a 2.1 percent decrease in kWh sales from 2017. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through PSAs of various durations.

Kilowatt-hours Sold	2018	2017	Quantity Variance		% Variance
Millions
Regulated Utility
Retail and Municipal
Residential	1,140	1,096	44		4.0
Commercial	1,426	1,420	6		0.4
Industrial	7,261	7,327	(66	)	(0.9	)
Municipal	798	799	(1	)	(0.1	)
Total Retail and Municipal	10,625	10,642	(17	)	(0.2	)
Other Power Suppliers	3,953	4,039	(86	)	(2.1	)
Total Regulated Utility Kilowatt-hours Sold	14,578	14,681	(103	)	(0.7	)

Revenue from electric sales to taconite and iron concentrate customers accounted for 21 percent of consolidated operating revenue in 2018 (22 percent in 2017). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 4 percent of consolidated operating revenue in 2018 (5 percent in 2017). Revenue from electric sales to pipelines and other industrial customers accounted for 6 percent of consolidated operating revenue in 2018 (7 percent in 2017).

Cost recovery rider revenue increased $13.0 million primarily due to higher expenditures related to the construction of the GNTL and fewer production tax credits recognized by Minnesota Power. If production tax credits are recognized at a level below those assumed in Minnesota Power’s base rates, an increase in cost recovery rider revenue is recognized to offset the impact of lower production tax credits on income tax expense.

Fuel adjustment clause recoveries increased $7.9 million due to higher fuel and purchased power costs attributable to retail and municipal customers.

Conservation improvement program recoveries increased $3.5 million from 2017 primarily due to an increase in related expenditures. (See Operating Expenses - Operating and Maintenance.)

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2018 Compared to 2017 (Continued)

Regulated Operations (Continued)

Operating Expensesincreased$28.9 million, or 3 percent, from 2017.

Fuel, Purchased Power and Gas – Utility expense increased$10.6 million, or 3 percent, from 2017 primarily due to higher purchased power prices and higher fuel costs, partially offset by a $19.5 million expense in 2017 for the MPUC’s decision disallowing recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs. At a hearing on January 18, 2018, the MPUC disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million charge in the fourth quarter of 2017. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue – Utility.)

Operating and Maintenance expense decreased$7.2 million, or 3 percent, from 2017 primarily due to lower salary and benefit expenses, and lower materials purchased for generation facilities, partially offset by a $3.5 million increase in conservation improvement program expenses and additional severance expense of $1.9 million in 2018. (See Operating Revenue – Utility.)

Depreciation and Amortization expense increased$25.4 million, or 19 percent, from 2017 primarily due to modifications of the depreciable lives for Boswell and additional property, plant and equipment in service. As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million in 2017. Subsequently, as part of the reconsideration of its decision in Minnesota Power’s 2016 general rate case, the MPUC reduced the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035, resulting in higher depreciation expense in 2018. The increase in depreciation expense in 2018 was offset mostly by the benefits of the lower federal income tax rate enacted as part of the TCJA. (See Note 4. Regulatory Matters and Income Tax Benefit.)

Interest Expenseincreased$3.2 million, or 6 percent, from 2017 primarily due to higher average long-term debt balances, higher interest rates and $0.5 million of interest on Minnesota Power’s reserve for interim rate refunds. We record interest expense for Regulated Operations primarily based on rate base and authorized capital structure, and allocate the balance to Corporate and Other.

Equity Earnings in ATC decreased$5.0 million, or 22 percent, from2017 primarily due to the federal income tax rate change enacted as part of the TCJA, partially offset by additional investments in ATC. (See Note 5. Equity Investments.)

Income Tax Benefit was $15.5 million in 2018 compared to income tax expense of $27.2 million in 2017. The income tax benefit in 2018 reflects the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, the amortization of excess deferred income tax benefit resulting from the TCJA and lower pre-tax income. Income tax expense in 2017 included the impact of a regulatory outcome in 2017 related to the allocation of North Dakota investment tax credits.

In 2017, as a result of the favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits, Regulated Operations increased operating revenue and reduced the corresponding regulatory liability by $14.0 million resulting in an income tax expense of $6.1 million. In addition, Regulated Operations recorded an income tax expense of $7.9 million for North Dakota investment tax credits transferred to Corporate and Other, resulting in no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax benefit of $7.9 million for the North Dakota investment tax credits transferred from Regulated Operations. (See Note 4. Regulatory Matters.)

ALLETE Clean Energy

Year Ended December 31	2018		2017
Millions
Operating Revenue		$159.9		$80.5
Net Income Attributable to ALLETE (a)	$33.7			$41.5

(a) Results in 2017 include a $23.6 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

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2018 Compared to 2017 (Continued)

ALLETE Clean Energy (Continued)

Operating Revenueincreased$79.4 million from 2017 due to the sale of a wind energy facility to Montana-Dakota Utilities in 2018.

	Year Ended December 31,
	2018			2017
Production and Operating Revenue	kWh	Revenue		kWh	Revenue
Millions
Wind Energy Facility
Lake Benton	220.1		$11.9	241.8		$12.3
Storm Lake II	134.8	9.5		152.6	10.0
Condon	99.6	8.1		90.7	7.5
Storm Lake I	191.8	11.7		215.6	12.4
Chanarambie/Viking	244.9	13.5		263.5	13.9
Armenia Mountain	264.5	24.1		267.4	24.4
Total Wind Energy Facilities	1,155.7	78.8		1,231.6	80.5
Sale of Wind Energy Facility (a)	—	81.1		—	—
Total Production and Operating Revenue	1,155.7	$159.9		1,231.6		$80.5

(a)    2018 included the recognition of $67.4 million of cost of sales related to the sale of a wind energy facility.

Net Income Attributable to ALLETE decreased$7.8 million from 2017. Net income in 2017 included a $23.6 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. Net income in 2018 included the sale of a wind energy facility to Montana-Dakota Utilities, a lower federal income tax rate enacted as part of the TCJA and $7.4 million after-tax of additional production tax credits generated as ALLETE Clean Energy continues to execute its refurbishment strategy. Of the $7.4 million after-tax in additional production tax credits, $3.0 million resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017. These increases were partially offset by higher operating and maintenance expenses.

U.S. Water Services

Year Ended December 31	2018		2017
Millions
Operating Revenue		$172.1		$151.8
Net Income Attributable to ALLETE (a)	$3.2			$10.7

(a) Results in 2017 include a $9.2 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Operating Revenue increased$20.3 million, or 13 percent, from 2017. Revenue from chemical sales and related services was $138.6 million in 2018 compared to $132.0 million in 2017. Revenue from capital projects was $33.5 million for 2018 compared to $19.8 million in 2017; capital project sales can significantly fluctuate from period to period. Revenue in 2018 reflected a full year of sales from Tonka Water, which was acquired in September 2017.

Net Income Attributable to ALLETE decreased$7.5 million from 2017. Net income in 2017 included a $9.2 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. Net income in 2018 included increased revenue primarily due to higher capital project sales and higher sales of chemicals and related services, partially offset by higher operating expenses. Net income in 2018 included $0.6 million of after-tax expense recognized as cost of sales related to purchase accounting for sales backlog.

Cash flow from operations for U.S. Water Services was approximately $5 million in 2018 compared to approximately $12 million in 2017.

Corporate and Other

Operating Revenuedecreased$16.1 million, or 13 percent, from 2017 primarily due to a decrease in land sales at ALLETE Properties and lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses and fewer tons sold in 2018 compared to 2017.

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2018 Compared to 2017 (Continued)

Corporate and Other (Continued)

Net Income Attributable to ALLETE was $6.2 million in 2017 compared to a net loss of $8.4 million in 2017. The net loss in 2017 included additional income tax expense of $19.8 million after-tax for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA and a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits. Net income in 2018 included an increase for the change in fair value of the contingent consideration liability of $1.3 million after-tax.

Net income at BNI Energy was $6.8 million in 2018 compared to $4.5 million in 2017. Net income in 2017 included a $3.1 million after-tax expense due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. The net loss at ALLETE Properties was $0.5 million in 2018 compared to a net loss of $8.8 million in 2017. The net loss in 2017 included a $7.8 million after-tax expense for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Income Taxes – Consolidated

For the year ended December 31, 2018, the effective tax rate was a benefit of 9.8 percent (expense of 7.9 percent for the year ended December 31, 2017). The decrease from 2017 was primarily due to the reduction of the federal income tax rate from 35 percent to 21percentenacted as part of the TCJA, the amortization of excess deferred income tax benefit resulting from the TCJA and lower pre-tax income in 2018, partially offset by the remeasurement of deferred income tax assets and liabilities resulting from the TCJA in 2017. The effective rate deviated from the combined statutory rate of approximately 28 percent primarily due to production tax credits. (See Note 13. Income Tax Expense.)

2017 Compared to 2016

(See Note 17. Business Segments for financial results by segment.)

Regulated Operations

Year Ended December 31	2017			2016
Millions
Operating Revenue – Utility		$1,063.8			$1,000.7
Fuel, Purchased Power and Gas – Utility	396.9			339.9
Transmission Services – Utility	71.2			65.2
Operating and Maintenance	227.3			227.5
Depreciation and Amortization	132.6			154.3
Taxes Other than Income Taxes	51.1			47.7
Operating Income	184.7			166.1
Interest Expense	(57.0		)	(52.1		)
Equity Earnings in ATC	22.5			18.5
Other Income	5.4			8.9
Income Before Income Taxes	155.6			141.4
Income Tax Expense	27.2			5.9
Net Income Attributable to ALLETE	$128.4			$135.5

Operating Revenue – Utilityincreased $63.1 million, or 6 percent, from 2016 primarily due to the period over period impact of the regulatory outcomes related to the allocation of North Dakota investment tax credits, as well as higher fuel adjustment clause recoveries, conservation improvement program recoveries and revenue from kWh sales, partially offset by lower FERC formula-based rates, financial incentives under the conservation improvement program and transmission revenue. Interim retail rate refund reserves fully offset the interim retail rates recognized during 2017.

Revenue increased $29.0 million due to the period over period impact of the regulatory outcomes related to the allocation of North Dakota investment tax credits. As a result of the favorable impact for the regulatory outcome of the MPUC’s modification of its 2016 order on the allocation of North Dakota investment tax credits, operating revenue increased $14.0 million in 2017. In 2016, operating revenue decreased $15.0 million as a result of the adverse impact for the regulatory outcome of the 2016 MPUC order. (See Note 4. Regulatory Matters.)

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2017 Compared to 2016 (Continued)

Regulated Operations (Continued)

Fuel adjustment clause recoveries increased $24.4 million due to higher fuel and purchased power costs attributable to retail and municipal customers. (See Operating Expenses - Fuel, Purchased Power and Gas – Utility.)

Conservation improvement program recoveries increased $7.2 million from 2016 primarily due to an increase in related expenditures. (See Operating Expenses - Operating and Maintenance.)

Revenue from kWh sales increased $3.9 million from 2016 primarily due to higher sales to Industrial customers. Sales to Industrial customers increased13.5 percent primarily due to increased taconite production and the commencement of a long‑term PSA with Silver Bay Power in 2016. Sales to Other Power Suppliers decreased6.4 percent from 2016 as a result of increased sales to Industrial customers. 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; market prices were lower in 2017 compared to 2016. Sales to Residential, Commercial and Municipal customers decreased primarily due to milder temperatures in 2017.

Kilowatt-hours Sold	2017	2016	Quantity Variance		% Variance
Millions
Regulated Utility
Retail and Municipal
Residential	1,096	1,102	(6	)	(0.5	)
Commercial	1,420	1,442	(22	)	(1.5	)
Industrial	7,327	6,456	871		13.5
Municipal	799	816	(17	)	(2.1	)
Total Retail and Municipal	10,642	9,816	826		8.4
Other Power Suppliers	4,039	4,316	(277	)	(6.4	)
Total Regulated Utility Kilowatt-hours Sold	14,681	14,132	549		3.9

Revenue from electric sales to taconite and iron concentrate customers accounted for 22 percent of consolidated operating revenue in 2017 (18 percent in 2016). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of consolidated operating revenue in 2017 (6 percent in 2016). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2017 (7 percent in 2016).

Interim retail rates for Minnesota Power were approved by the MPUC and became effective on January 1, 2017. Interim retail rate refund reserves of $31.6 million fully offset the interim retail rates recognized during 2017 due to the regulatory outcome of the MPUC’s decision in Minnesota Power’s 2016 general rate case on January 18, 2018. (See Note 4. Regulatory Matters.)

Revenue from wholesale customers under FERC formula-based rates decreased $4.9 million from 2016 primarily due to lower rates.

Financial incentives under the conservation improvement program decreased $1.9 million from 2016.

Transmission revenue decreased $1.7 million primarily due to lower MISO-related revenue, partially offset by period over period changes in the estimate of a refund liability related to MISO return on equity complaints. (See Operating Expenses - Transmission Services – Utility.)

Operating Expensesincreased$44.5 million, or 5 percent, from 2016.

Fuel, Purchased Power and Gas – Utility expense increased$57.0 million, or 17 percent, from 2016 primarily due to increased kWh sales, higher fuel costs and a $19.5 million expense for the MPUC’s decision disallowing recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs at a hearing on January 18, 2018, due to the anticipated adoption of a forward-looking fuel adjustment clause methodology. These increases were partially offset by lower purchased power prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue – Utility.)

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2017 Compared to 2016 (Continued)

Regulated Operations (Continued)

Transmission Services – Utility expense increased$6.0 million, or 9 percent, from 2016 primarily due to higher MISO-related expense. (See Operating Revenue – Utility.)

Depreciation and Amortization expense decreased$21.7 million, or 14 percent, from 2016 primarily due to modifications of the depreciable lives for Boswell, partially offset by additional property, plant and equipment in service. At a hearing on January 18, 2018, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million in 2017.

Taxes Other than Income Taxes increased$3.4 million, or 7 percent, from 2016 primarily due to higher property tax expenses resulting from higher taxable plant.

Interest Expenseincreased$4.9 million, or 9 percent, from 2016 primarily due to higher average interest rates. We record interest expense for Regulated Operations primarily based on rate base and authorized capital structure, and allocate the balance to Corporate and Other.

Equity Earnings in ATC increased$4.0 million, or 22 percent, from2016 primarily due to additional investments in ATC and period over period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints. (See Note 5. Equity Investments.)

Income Tax Expenseincreased$21.3 million, from 2016 due to the period over period impact of the regulatory outcomes related to the allocation of North Dakota investment tax credits and higher pre-tax income. The TCJA did not have an impact on income tax expense for our Regulated Operations as the remeasurement of deferred income tax assets and liabilities primarily resulted in the recording of regulatory assets and liabilities.

In 2017, as a result of the favorable impact for the regulatory outcome of the MPUC’s modification of its 2016 order on the allocation of North Dakota investment tax credits, Regulated Operations increased operating revenue and reduced the corresponding regulatory liability by $14.0 million resulting in an income tax expense of $6.1 million. In addition, Regulated Operations recorded an income tax expense of $7.9 million for North Dakota investment tax credits transferred to Corporate and Other, resulting in no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax benefit of $7.9 million for the North Dakota investment tax credits transferred from Regulated Operations.

In 2016, as a result of the adverse impact for the regulatory outcome of the 2016 MPUC order, Regulated Operations reduced operating revenue and recorded a corresponding regulatory liability for $15.0 million resulting in an income tax benefit of $6.2 million. In addition, Regulated Operations recorded an income tax benefit of $8.8 million for North Dakota investment tax credits transferred from Corporate and Other, resulting in no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax expense of $8.8 million for the North Dakota investment tax credits transferred to Regulated Operations.

ALLETE Clean Energy

Year Ended December 31,	2017		2016
Millions
Operating Revenue		$80.5		$80.5
Net Income Attributable to ALLETE(a)	$41.5		$13.4

(a) Results in 2017 include a $23.6 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Operating Revenue isconsistent with 2016 as lower kWh sales at the wind energy facilities resulting from lower wind resources were offset by higher amortization of PSAs. (See Note 1. Operations and Significant Accounting Policies.)

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2017 Compared to 2016 (Continued)

ALLETE Clean Energy (Continued)

	Year Ended December 31,
	2017			2016
Production and Operating Revenue	kWh	Revenue		kWh	Revenue
Millions
Wind Energy Facility
Lake Benton	241.8		$12.3	254.7		$12.8
Storm Lake II	152.6	10.0		154.8	10.1
Condon	90.7	7.5		96.9	8.2
Storm Lake I	215.6	12.4		222.3	11.6
Chanarambie/Viking	263.5	13.9		278.8	13.4
Armenia Mountain	267.4	24.4		268.2	24.4
Total Production and Operating Revenue	1,231.6	$80.5		1,275.7		$80.5

Net Income Attributable to ALLETE increased$28.1 million from 2016. Net income in 2017 included a $23.6 million after‑tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, increased production tax credits due to the requalification of WTGs at ALLETE Clean Energy’s Storm Lake I, Storm Lake II and Lake Benton wind energy facilities, lower operating and maintenance expense, and lower interest expense compared to 2016. Net income in 2016 included a $3.3 million after-tax goodwill impairment charge and a $0.9 million after-tax expense related to the repayment of long-term debt. Net income in 2016 also included an allocation of earnings to a non-controlling interest in the limited liability company that owns the Condon wind energy facility, which was acquired by ALLETE Clean Energy in April 2016. (See Note 6. Acquisitions.)

U.S. Water Services

Year Ended December 31	2017		2016
Millions
Operating Revenue		$151.8		$137.5
Net Income Attributable to ALLETE (a)	$10.7			$1.5

(a) Results in 2017 include a $9.2 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Operating Revenue increased$14.3 million from 2016 primarily due to the acquisitions of WEST in 2016 and Tonka Water in September 2017. (See Note 6. Acquisitions.) Revenue from chemical sales and related services was $132.0 million in 2017 compared to $124.3 million in 2016. Revenue from capital project sales was $19.8 million for 2017 compared to $13.2 million in 2016; capital project sales can significantly fluctuate from period to period.

Net Income Attributable to ALLETE increased$9.2 million from 2016. Net income in 2017 included a $9.2 million after‑tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, and higher operating revenue, partially offset by increased operating expenses as a result of investments for future growth in waste treatment and water safety applications. Net income in 2017 also included a net loss of $0.8 million primarily for transaction fees and amortization expense of the Tonka Water acquisition in September 2017. (See Note 6. Acquisitions.)

Corporate and Other

Operating Revenueincreased$2.2 million, or 2 percent, from 2016 primarily due to an increase in revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of higher expenses and record coal sales in 2017, partially offset by a decrease in land sales at ALLETE Properties. Operating revenue in 2016 included the sale of ALLETE Properties’ Ormond Crossings project and Lake Swamp wetland mitigation bank for approximately $21 million.

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2017 Compared to 2016 (Continued)

Corporate and Other (Continued)

Net Loss Attributable to ALLETE was $8.4 million in 2017 compared to net income of $4.9 million in 2016. The net loss in 2017 included a $19.8 million after-tax expense due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. The net loss in 2017 also included a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of its 2016 order on the allocation of North Dakota investment tax credits, lower accretion expense relating to the contingent consideration liability, and lower interest expense. Net income in 2016 included an after‑tax gain of $13.6 million related to the change in fair value of the contingent consideration liability, partially offset by an $8.8 million after-tax adverse impact for the regulatory outcome of the 2016 MPUC order.

Net income at BNI Energy was $4.5 million in 2017 which included a $3.1 million after-tax expense due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, partially offset by more tons sold; net income in 2016 was $6.8 million. The net loss at ALLETE Properties was $8.8 million in 2017 which included a $7.8 million after-tax expense for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA; net income in 2016 was $0.7 million.

Income Taxes – Consolidated

For the year ended December 31, 2017, the effective tax rate was 7.9 percent (11.3 percent for the year ended December 31, 2016). The decrease from 2016 was primarily due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA and increased production tax credits, partially offset by higher pre-tax income. (See Regulated Operations - Income Tax Expense.) The effective rate deviated from the combined statutory rate of approximately 41 percent primarily due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, and production tax credits. (See Note 13. Income Tax Expense.)

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

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Critical Accounting Policies (Continued)

Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and other postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of several important assumptions, including the expected long-term rate of return on plan assets, the discount rate and mortality assumptions, among others, in determining our obligations and the annual cost of our pension and other postretirement benefits. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class and adjust these for current economic conditions while utilizing the target allocation of our plan assets to forecast the expected long-term rate of return. Our pension asset allocation as of December 31, 2018, was approximately 32 percent equity securities, 60 percent fixed income, 5 percent private equity and 3 percent real estate. Our postretirement health and life asset allocation as of December 31, 2018, was approximately 62 percent equity securities, 34 percent fixed income and 4 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2018, we used expected long-term rates of return of 7.50 percent in our actuarial determination of our pension expense and 6.00 percent to 7.50 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 $1.8 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 2018, we used discount rates of 3.81 percent to 3.96 percent and 3.86 percent in our actuarial determination of our pension and other postretirement expense, respectively. We review our discount rates annually and will adjust them to respond to changing market conditions. A one-quarter percent decrease in the discount rate would increase the annual expense for pension and other postretirement benefits by approximately $1.7 million, pre‑tax.

The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2018, considered a modified RP-2014 mortality table and mortality projection scale. (See Note 15. Pension and Other Postretirement Benefit Plans.)

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

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

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

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

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Critical Accounting Policies (Continued)

Valuation of Goodwill and Intangible Assets. 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 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. The fair value assigned to intangible assets is determined by estimating the future cash flows of each project and discounting the net cash flows back to their present values. The discount rate used is determined at the time of measurement in accordance with accepted valuation standards.

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. 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, including projected future cash flows. The results of our annual impairment test are discussed in Note 1. Operations and Significant Accounting Policies and Note 9. Fair Value in this Form 10-K. Goodwill was $148.5 million and $148.3 million as of December 31, 2018, and December 31, 2017, respectively.

Intangible Assets.Intangible assets include customer relationships, patents, non-compete agreements, land easements, trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents, non-compete agreements, land easements and certain trade names, which are amortized on a straight-line basis with estimated useful lives ranging from approximately 4 years to approximately 19 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite-lived intangible assets consist of trademarks and certain trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Our impairment reviews are based on an estimated future cash flow approach that requires significant judgment with respect to future revenue and expense growth rates, selection of an appropriate discount rate, and other assumptions and estimates. We use estimates that are consistent with our business plans and a market participant view of the assets being evaluated. The results of our annual impairment test are discussed in Note 9. Fair Value in this Form 10-K. Intangible assets, net of accumulated amortization, were $74.8 million and $77.6 million as of December 31, 2018, and December 31, 2017, respectively.

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 long-term objectives of achieving average annual earnings per share growth of 5 percent to 7 percent, and providing a dividend payout competitive with our industry. Regulated Operations is projected to have average annual earnings growth of 4 percent to 5 percent and our Energy Infrastructure and Related Services businesses are projected to have average annual earnings growth of at least 15 percent over the long-term.

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 its Energy Infrastructure and Related Services 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 80 percent of total consolidated net income in 2019. Over the next several years, the contribution of the Energy Infrastructure and Related Services businesses to net income is expected to increase as ALLETE grows these operations. ALLETE expects its businesses to provide regulated, contracted or recurring revenues, and to support sustained growth in net income and cash flow.

On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million, subject to adjustment at closing, such as for changes in working capital. The transaction is expected to close by the end of the first quarter of 2019 upon receipt of regulatory approval. ALLETE plans to use the proceeds from the sale of U.S. Water Services primarily to reinvest in growth initiatives at our Regulated Operations and ALLETE Clean Energy. ALLETE will also consider using a portion of the proceeds to implement a common stock repurchase program.

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Outlook (Continued)

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. (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. Minnesota Power anticipates filing a rate case in the fourth quarter of 2019 with a 2020 test year.

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.

2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC which sought an average increase of approximately 9 percent for retail customers. The rate filing sought a return on equity of 10.25 percent and a 53.81 percent equity ratio. The MPUC issued an order dated March 12, 2018, in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which is expected to result in additional revenue of approximately $13 million on an annualized basis. Interim rates were collected from January 1, 2017, through November 30, 2018, which were fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund, net of discounts provided to EITE customers, of $40.0 million as of December 31, 2018 ($23.7 million as of December 31, 2017) which is expected to be refunded in 2019. The MPUC also disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC also extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million in the fourth quarter of 2017.

On April 2, 2018, Minnesota Power filed a petition with the MPUC requesting reconsideration of certain decisions in the MPUC’s order dated March 12, 2018. In an order dated May 29, 2018, the MPUC denied Minnesota Power’s petition for reconsideration and accepted a Minnesota Department of Commerce request for reconsideration reducing the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 while utilizing the benefits of the lower federal income tax rate enacted as part of the TCJA to mitigate the impact on customer rates.

Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 establishing a Minnesota energy policy to have competitive rates for certain industries such as mining and forest products. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an April 2017 order. Minnesota Power expects the discount to EITE customers to be approximately $16 million annually based on EITE customer current operating levels. While interim rates were in effect for Minnesota Power’s 2016 general rate case, discounts provided to EITE customers offset interim rate refund reserves for non-EITE customers. Minnesota Power provided $16.7 million of discounts to EITE customers during the year ended December 31, 2018 ($8.6 million and none for the years ended December 31, 2017, and 2016, respectively).

2016 Wisconsin General Rate Case.SWL&P’s retail rates in 2018 were based on a 2017 PSCW retail rate order effective August 2017 that allowed for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 2017 were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity.

2018 Wisconsin General Rate Case. On May 25, 2018, SWL&P filed a rate increase request with the PSCW requesting an average increase of 2.7 percent for retail customers (2.0 percent increase in electric rates; 2.3 percent increase in natural gas rates; and 0.1 percent increase in water rates). The filing sought an overall return on equity of 10.5 percent and a 55.41 percent equity ratio. In an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return of equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of approximately $1.3 million on an annualized basis.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and secondary wood products, pipeline and other industries. Approximately 50 percent of our regulated utility kWh sales in 2018 (50 percent in 2017 and 45 percent in 2016) were made to our industrial customers. We expect industrial sales of approximately 7.0 million to 7.5 million MWh in 2019 (7.3 million MWh in 2018; 7.3 million MWh in 2017). (See Item 1. Business – Regulated Operations – Electric Sales / Customers.)

Taconite and Iron Concentrate. Minnesota Power’s taconite customers are capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than 10 percent of Minnesota taconite production has been exported outside of North America. Minnesota Power also has provided electric service to three iron concentrate facilities capable of producing up to approximately 4 million tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets. These facilities have been idled since at least 2016. On July 17, 2018, ERP Iron Ore announced it would no longer seek to restart its operations. (See ERP Iron Ore /Magnetation.)

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 78 percent of capacity in 2018 (74 percent in 2017 and 71 percent in 2016). The World Steel Association, an association of over 160 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 2019 will increase by approximately one percent compared to 2018.

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

USS Corporation. In the first quarter of 2017, USS Corporation restarted its Minnesota Ore Operations Keetac plant in Keewatin, Minnesota, which had been idled since 2015. USS Corporation has the capability to produce approximately 5 million tons at its Keetac Plant.

United Taconite. In May 2017, Cliffs announced that production of a fully fluxed taconite pellet has started at its United Taconite facility. The product replaced a flux pellet previously made at Cliffs’ indefinitely idled Empire operation in Michigan. United Taconite has the capability to produce approximately 5 million tons of taconite annually.

Northshore Mining. Cliffs has announced that it is investing further in its Minnesota ore operations, specifically it plans to invest approximately $90 million through 2020 to expand capacity for producing direct reduced-grade pellets at Northshore Mining. The additional direct reduced-grade pellets could be sold commercially or used to supply Cliff’s planned hot briquetted iron production plant in Toledo, Ohio. Minnesota Power has a PSA through 2031 with Silver Bay Power, which provides the majority of the electric service requirements for Northshore Mining. (See Silver Bay Power.)

Silver Bay Power. In 2016, Minnesota Power and Silver Bay Power entered into a PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which has been served predominately through self-generation by Silver Bay Power. Through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power has the option to purchase additional energy from Minnesota Power as it transitions away from self-generation. By December 31, 2019, Silver Bay Power is expected to cease self-generation and Minnesota Power is expected to supply the energy requirements for Silver Bay Power.

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Outlook (Continued)

Industrial Customers and Prospective Additional Load (Continued)

ERP Iron Ore / Magnetation. In January 2017, ERP Iron Ore purchased substantially all of Magnetation’s assets pursuant to an asset purchase agreement approved by the U. S. Bankruptcy Court for the District of Minnesota. These facilities have been idled since at least 2016. On July 17, 2018, ERP Iron Ore filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Minnesota and announced that it would no longer seek to restart its operations. Minnesota Power has reserved for all receivables due from ERP Iron Ore.

Paper, Pulp and Secondary Wood Products. The four major paper and pulp mills we serve reported operating at lower levels in 2018 compared to 2017 resulting from the closure of the smaller of UPM Blandin’s two paper machines in the fourth quarter of 2017. (See UPM Blandin.) We expect operating levels in 2019 to be similar to 2018.

UPM Blandin. In October 2017, UPM-Kymmene Corporation announced that in light of the global market for graphic papers, and to sustain its competitiveness and leading position in the market, it planned to permanently close the smaller of UPM Blandin’s two paper machines located in Grand Rapids, Minnesota; the closure was completed in the fourth quarter of 2017. Paper production related to the other paper machine is planned to continue at UPM Blandin. Minnesota Power provides electric and steam service to UPM Blandin. In October 2018, Minnesota Power amended and extended its electric service agreement with UPM Blandin through 2029, subject to MPUC approval.

Verso Corporation.In the third quarter of 2018, Minnesota Power amended and extended its electric service agreement with Verso Corporation through 2024, which was approved by the MPUC at a hearing on December 20, 2018.

Pipeline and Other Industries.

Husky Energy.On April 26, 2018, a fire at Husky Energy’s refinery in Superior, Wisconsin disrupted operations at the facility. Under normal operating conditions, SWL&P provides approximately 14 MW of average monthly demand to Husky Energy in addition to water service. The facility remains at minimal operations, and the refinery is not expected to resume normal operations in 2020.

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

Nashwauk Public Utilities Commission. Mesabi Metallics is a retail customer of the Nashwauk Public Utilities Commission, and Minnesota Power has a wholesale electric contract with the Nashwauk Public Utilities Commission for electric service through at least December 2032. Mesabi Metallics filed for bankruptcy protection in 2016 under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. In June 2017, the bankruptcy court approved a settlement plan for a consortium led by Chippewa Capital Partners LLC to take control of the project, subject to certain stipulations. In December 2017, Mesabi Metallics emerged from bankruptcy under the ownership of Chippewa Capital Partners LLC.

PolyMet. PolyMet is planning to start a new copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. In 2015, PolyMet announced the completion of the final EIS by state and federal agencies, which was subsequently published in the Federal Register and Minnesota Environmental Quality Board Monitor. The Minnesota Department of Natural Resources (DNR) issued its Record of Decision in 2016, finding the final EIS adequate. The final EIS also requires Records of Decision by the federal agencies, which are expected in 2019, before final action can be taken on the required federal permits to construct and operate the mining operation.

In 2016, PolyMet submitted applications for water-related permits with the DNR and MPCA, an air quality permit with the MPCA, and a state permit to mine application with the DNR detailing its operational plans for the mine. On November 1, 2018, the DNR issued PolyMet’s permit to mine and certain water-related permits. On December 20, 2018, the MPCA issued PolyMet’s final state water and air quality permits. PolyMet’s remaining federal permit is under review by the U.S. Army Corps of Engineers. On June 28, 2018, the U.S. Forest Service and PolyMet closed on a land exchange, which resulted in PolyMet obtaining surface rights to land needed to develop its mining operation. Minnesota Power could supply between 45 MW and 50 MW of load under a 10‑year power supply contract with PolyMet that would begin upon start-up of operations.

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Outlook (Continued)

EnergyForward. Minnesota Power is executing EnergyForward, a strategic plan for 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 of certain coal-fired generating facilities.

In July 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas capacity dedication agreement. These agreements were subject to MPUC approval of the construction of NTEC, a 525 MW to 550 MW combined-cycle natural gas-fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In an order dated January 24, 2019, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet including potential early retirement scenarios of Boswell Units 3 and 4, including a securitization plan. The MPUC also approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2020. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW. A decision on the application is expected in 2020.

On June 18, 2018, Minnesota Power filed a separate petition for approval of the PPA for the output of the 10 MW solar energy facility to be located in central Minnesota, which was approved by the MPUC in an order dated October 2, 2018. On August 22, 2018, Minnesota Power filed a separate petition for approval of an amended PPA for the output of the 250 MW wind energy facility to be located in southwestern Minnesota which was approved in an order dated January 23, 2019. (See Note 5. Equity Investments.)

Integrated Resource Plan. In 2015, Minnesota Power filed its 2015 IRP with the MPUC, which included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contained steps in Minnesota Power’s EnergyForward strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for Taconite Harbor, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. (See Note 4. Regulatory Matters.)

Renewable Energy. Minnesota Power’s 2015 IRP includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. Minnesota Power continues to execute its renewable energy strategy through renewable projects that will ensure it meets the identified state mandate at the lowest cost for customers. Minnesota Power has exceeded the interim milestone requirements to date and expects between 25 percent and 30 percent of its applicable retail and municipal energy sales will be supplied by renewable energy sources in 2019. (See Item 1. Business – Regulated Operations – Minnesota Legislation and EnergyForward.)

Minnesota Solar Energy Standard. Minnesota Power’s solar energy supply consists of Camp Ripley, a 10 MW solar energy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, and a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. In an order dated October 2, 2018, the MPUC approved a PPA for the output of the 10 MW Blanchard solar energy facility to be located in central Minnesota. Minnesota Power expects that Camp Ripley, the community solar garden arrays, the PPA for the output of the 10 MW Blanchard solar energy facility, and an increase in solar rebates will allow Minnesota Power to meet both parts of the solar mandate. (See Item 1. Business – Regulated Operations – Minnesota Legislature and EnergyForward.)

Minnesota Power has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. Currently, there is no approved customer billing rate for solar costs.

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.

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Outlook (Continued)

EnergyForward (Continued)

Minnesota Power uses the 465-mile, 250-kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota, to transport increasing amounts of 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 DC transmission line capacity can be increased if renewable energy or transmission needs justify investments to upgrade the line.

Minnesota Power has an approved cost recovery rider for certain renewable investments and expenditures. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of certain renewable investments plus a return on the capital invested. Updated customer billing rates for the renewable cost recovery rider were provisionally approved by the MPUC in an order dated November 19, 2018.

Nobles 2 PPA. In the third quarter of 2018, Minnesota Power and Nobles 2 signed an amended long-term PPA that provides for Minnesota Power to purchase the energy and associated capacity from a 250 MW wind energy facility in southwestern Minnesota for a 20-year period beginning in 2020. 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. This agreement is subject to construction of the wind energy facility. (See Note 5. Equity Investments.)

Manitoba Hydro. Minnesota Power has five long-term PPAs with Manitoba Hydro. The first PPA expires in May 2020. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index. Under the second PPA, Minnesota Power is purchasing surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.

The third PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The PPA is subject to construction of the GNTL and MMTP. (See Note 11. Commitments, Guarantees and Contingencies.) The capacity price is 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 price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

The fourth PPA provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The pricing under this PPA is based on forward market prices. The PPA is subject to the construction of the GNTL and MMTP. (See Note 11. Commitments, Guarantees and Contingencies.)

The fifth PPA provides for Minnesota Power to purchase 50 MW of capacity from Manitoba Hydro at fixed prices. The PPA began in June 2017 and expires in May 2020.

Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. See also Item 1. Business – Regulated Operations and Note 11. Commitments, Guarantees and Contingencies.

Energy Infrastructure and Related Services.

ALLETE Clean Energy.

ALLETE Clean Energy will pursue growth through acquisitions or project development. ALLETE Clean Energy is targeting acquisitions of existing facilities up to 200 MW each, which have long-term PSAs in place for the facilities’ output. At this time, ALLETE Clean Energy expects acquisitions or development of new facilities will be primarily wind or solar facilities in North America. ALLETE Clean Energy is also targeting the development of new facilities up to 200 MW each, which will have long‑term PSAs in place for the output or may be sold upon completion. (See Item 1. Business – Energy Infrastructure and Related Services – ALLETE Clean Energy.)

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Outlook (Continued)

ALLETE Clean Energy (Continued)

Federal production tax credit qualification is important to the economics of project development, and in 2016, 2017, and 2018 ALLETE Clean Energy invested in equipment to meet production tax credit safe harbor provisions which provides an opportunity to seek development of up to approximately 1,500 MW of production tax credit qualified wind projects through 2022. ALLETE Clean Energy will also invest approximately $80 million through 2020 for production tax credit requalification of up to 385 WTGs at its Storm Lake I, Storm Lake II and Lake Benton wind energy facilities. On December 18, 2018, ALLETE Clean Energy announced it will requalify its Condon wind energy facility for production tax credits, which will be completed in 2019. We anticipate annual production tax credits relating to these projects of approximately $14 million in 2019, $17 million to $22 million annually in 2020 through 2027, and decreasing thereafter through 2030.

In January 2017, ALLETE Clean Energy announced that it would develop a wind energy facility of up to 50 MW to be sold to Montana-Dakota Utilities; sale of the wind energy facility was completed on October 31, 2018, with revenue of $81.1 million and cost of sales of $67.4 million recognized in the fourth quarter of 2018. ALLETE Clean Energy also constructed and sold a 107 MW wind energy facility to Montana-Dakota Utilities in 2015.

In March 2017, ALLETE Clean Energy announced it will build, own and operate a 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction is expected to be completed in late 2019. On March 15, 2018, ALLETE Clean Energy announced that it will build, own and operate an 80 MW wind energy facility pursuant to a 15-year PSA with NorthWestern Corporation; construction is expected to be completed in late 2019.

ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current portfolio of approximately 545 MW 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. The current mix of PSA expiration and geographic location for existing facilities is as follows:

Wind Energy Facility	Location	Capacity MW	PSA MW	PSA Expiration
Armenia Mountain	Pennsylvania	100.5	100%	2024
Chanarambie/Viking	Minnesota	97.5
PSA 1 (a)			12%	2023
PSA 2			88%	2023
Condon	Oregon	50	100%	2022
Lake Benton	Minnesota	104	100%	2028
Lincoln Heights	Minnesota	8.8	100%	2028
Storm Lake I	Iowa	108	100%	2019
Storm Lake II	Iowa	77
PSA 1			90%	2019
PSA 2			10%	2032

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

U.S. Water Services.

On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million, subject to adjustment at closing, such as for changes in working capital. The transaction is expected to close by the end of the first quarter of 2019 upon receipt of regulatory approval. ALLETE plans to use the proceeds from the sale of U.S. Water Services primarily to reinvest in growth initiatives at our Regulated Operations and ALLETE Clean Energy. ALLETE will also consider using a portion of the proceeds to implement a common stock repurchase program.

ALLETE, Inc. 2018 Form 10-K

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Outlook (Continued)

Corporate and Other.

BNI Energy.In 2018, BNI Energy sold 4.3 million tons of coal (4.7 million tons in 2017) and anticipates 2019 sales will be similar to 2018. BNI Energy operates under cost-plus fixed fee agreements extending through December 31, 2037.

Investment in Nobles 2. On December 27, 2018, our wholly-owned subsidiary, ALLETE South Wind, entered into a partnership agreement with Tenaska to purchase a 49 percent equity interest in Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. The wind energy facility will be built in Nobles County, Minnesota and is expected to be completed in late 2020, with an estimated total project cost of approximately $350 million to $400 million of which our portion is expected to be approximately $170 million to $200 million. We expect to utilize tax equity to finance a portion of our project costs, with an ALLETE expected equity investment of approximately $60 million to $70 million. We account for our investment in Nobles 2 under the equity method of accounting. As of December 31, 2018, our equity investment in Nobles 2 was $33.0 million. (See Note 5. Equity Investments.)

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. Market conditions can impact land sales and could result in our inability to cover our cost basis and operating expenses including fixed carrying costs such as community development district assessments and property taxes.

Income Taxes

ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 28 percent for 2018. 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 investment tax credits, production tax credits, AFUDC‑Equity, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income before income taxes, state and federal tax law changes that become effective during the year, business combinations, tax planning initiatives and resolution of prior years’ tax matters. We expect our effective tax rate to be a benefit of approximately 10 percent for 2019 primarily due to federal production tax credits as a result of wind energy generation. We also expect that our effective tax rate will be lower than the combined statutory rate over the next 11 years due to production tax credits attributable to our wind energy generation.

Liquidity and Capital Resources

Liquidity Position. ALLETE is well-positioned to meet its liquidity needs. As of December 31, 2018, we had cash and cash equivalents of $69.1 million, $388.6 million in available consolidated lines of credit and a debt-to-capital ratio of 41 percent.

On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million, subject to adjustment at closing, such as for changes in working capital. The transaction is expected to close by the end of the first quarter of 2019 upon receipt of regulatory approval. ALLETE plans to use the proceeds from the sale of U.S. Water Services primarily to reinvest in growth initiatives at our Regulated Operations and ALLETE Clean Energy. ALLETE will also consider using a portion of the proceeds to implement a common stock repurchase program.

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

As of December 31	2018		%	2017	%	2016	%
Millions
ALLETE Equity		$2,155.8