Document and Entity Information Document - USD ($)	12 Months Ended
Document and Entity Information Document - USD ($)	Dec. 31, 2019	Feb. 01, 2020	Jun. 30, 2019
Document and Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-3548
Entity Registrant Name	ALLETE, Inc.
Entity Incorporation, State	MN
Entity Tax Identification Number	41-0418150
Entity Address, Address Line	30 West Superior Street
Entity Address, City	Duluth
Entity Address, State	MN
Entity Address, Postal Zip Code	55802-2093
City Area Code	218
Local Phone Number	279-5000
Title of 12(b) Security	Common Stock, without par value
Trading Symbol	ALE
Security Exchange Name	NYSE
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 4,285,299,935
Entity Common Stock, Shares Outstanding		51,696,497
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current Assets [Abstract]
Cash and Cash Equivalents	$ 69.3	$ 69.1
Accounts Receivable (Less Allowance of $0.9 and $1.7)	96.4	144.4
Inventories – Net	72.8	86.7
Prepayments and Other	31.0	34.1
Total Current Assets	269.5	334.3
Property, Plant and Equipment – Net	4,377.0	3,904.4
Regulatory Assets	420.5	389.5
Equity Investments	197.6	161.1
Goodwill and Intangible Assets – Net	1.0	223.3
Other Non-Current Assets	217.2	152.4
Total Assets	5,482.8	5,165.0
Current Liabilities [Abstract]
Accounts Payable	165.2	149.8
Accrued Taxes	50.8	51.4
Accrued Interest	18.1	17.9
Long-Term Debt Due Within One Year	212.9	57.5
Other	60.4	128.5
Total Current Liabilities	507.4	405.1
Long-Term Debt	1,400.9	1,428.5
Deferred Income Taxes	212.8	223.6
Regulatory Liabilities	560.3	512.1
Defined Benefit Pension and Other Postretirement Benefit Plans	172.8	177.3
Other Non-Current Liabilities	293.0	262.6
Total Liabilities	3,147.2	3,009.2
Commitments, Guarantees and Contingencies (Note 9)
ALLETE's Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 51.7 and 51.5 Shares Issued and Outstanding	1,436.7	1,428.5
Accumulated Other Comprehensive Loss	(23.6)	(27.3)
Retained Earnings	818.8	754.6
Total ALLETE Equity	2,231.9	2,155.8
Non-controlling Interest in Subsidiaries	103.7	0.0
Total Equity	2,335.6	2,155.8
Total Liabilities and Equity	$ 5,482.8	$ 5,165.0

Consolidated Balance Sheet Parentheticals - USD ($)
shares in Millions, $ in Millions

Dec. 31, 2019

Dec. 31, 2018

Accounts Receivable [Abstract]

Accounts Receivable, Allowance for Credit Loss, Current

^[1]

$ 0.9

$ 1.7

Common Stock [Abstract]

Common Stock, Par Value Per Share

$ 0.00

Common Stock, Shares Authorized

80.0

Common Stock, Shares Outstanding

51.7

51.5

Common Stock, Shares Issued

51.7

51.5

[1]	On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related accounts receivable from the Consolidated Balance Sheet.

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenue [Abstract]
Contracts with Customers – Utility	$ 1,042.4	$ 1,059.5	$ 1,063.8
Contracts with Customers – Non-utility	186.5	415.5	331.9
Other – Non-utility	11.6	23.6	23.6
Total Operating Revenue	1,240.5	1,498.6	1,419.3
Operating Expenses [Abstract]
Fuel, Purchased Power and Gas - Utility	390.7	407.5	396.9
Transmission Services - Utility	69.8	69.9	71.2
Cost of Sales - Non-utility	80.6	218.0	147.5
Operating and Maintenance	264.3	340.5	344.1
Depreciation and Amortization	202.0	205.6	177.5
Taxes Other Than Income Taxes	53.3	57.9	56.9
Operating Expenses – Other	0.0	(2.0)	(0.7)
Total Operating Expenses	1,060.7	1,297.4	1,193.4
Operating Income	179.8	201.2	225.9
Other Income (Expense) [Abstract]
Interest Expense	(64.9)	(67.9)	(67.8)
Equity Earnings	21.7	17.5	22.5
Gain on Sale of U.S. Water Services	23.6	0.0	0.0
Other	18.7	7.8	6.3
Total Other Expense	(0.9)	(42.6)	(39.0)
Income Before Non-Controlling Interest and Income Taxes	178.9	158.6	186.9
Income Tax Expense	(6.6)	(15.5)	14.7
Net Income	185.5	174.1	172.2
Less: Non-Controlling Interest in Subsidiaries	(0.1)	0.0	0.0
Net Income Attributable to ALLETE	$ 185.6	$ 174.1	$ 172.2
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	51.6	51.3	50.8
Diluted (Shares)	51.7	51.5	51.0
Basic Earnings Per Share of Common Stock	$ 3.59	$ 3.39	$ 3.39
Diluted Earnings Per Share of Common Stock	$ 3.59	$ 3.38	$ 3.38

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Comprehensive Income [Abstract]
Net Income	$ 185.5	$ 174.1	$ 172.2
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities - Net of Income Tax Expense (Benefit) of $0.1, $- and $0.7	0.2	(0.1)	0.9
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Tax Expense (Benefit) of $1.4, $0.3 and $2.2	3.5	1.0	4.7
Total Other Comprehensive Income (Loss)	3.7	0.9	5.6
Total Comprehensive Income	189.2	175.0	177.8
Less: Non-Controlling Interest in Subsidiaries	(0.1)	0.0	0.0
Total Comprehensive Income Attributable to ALLETE	$ 189.3	$ 175.0	$ 177.8

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

Consolidated Statement of Cash Flows - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Operating Activities

Net Income

$ 185.5

$ 174.1

$ 172.2

AFUDC – Equity

(2.3)

(1.2)

Income from Equity Investments – Net of Dividends

(5.6)

(2.3)

(3.2)

Change in Fair Value of Contingent Consideration

^[1]

0.0

(2.0)

(0.7)

Deferred Fuel Adjustment Clause Charge

0.0

19.5

Loss (Gain) on Sales of Investments and Property, Plant and Equipment

(1.7)

1.0

0.4

Depreciation Expense

200.6

200.1

171.9

Amortization of PSAs

(11.6)

(23.6)

Amortization of Other Intangible Assets and Other Assets

13.0

10.4

10.2

Deferred Income Tax Expense (Benefit)

(6.7)

(15.8)

14.4

Share-Based and ESOP Compensation Expense

6.3

6.8

6.6

Defined Benefit Pension and Other Postretirement Benefit Expense

1.2

8.6

10.1

Bad Debt Expense

(0.1)

1.1

0.8

Provision for Interim Rate Refund

(40.0)

16.3

32.3

Provision for Tax Reform Refund

(10.4)

10.7

0.0

Gain on Sale of U.S. Water Services

(23.6)

0.0

Changes in Operating Assets and Liabilities

Accounts Receivable

22.6

(10.7)

(8.0)

Inventories

(4.1)

55.5

11.9

Prepayments and Other

0.3

(4.0)

(5.3)

Accounts Payable

(8.8)

13.6

(7.5)

Other Current Liabilities

(13.7)

6.7

1.8

Cash Contributions to Defined Benefit Pension Plans

(10.4)

(15.0)

(1.7)

Changes in Regulatory and Other Non-Current Assets

(25.1)

6.7

33.7

Changes in Regulatory and Other Non-Current Liabilities

(15.9)

(3.9)

(31.7)

Cash from Operating Activities

249.5

433.1

402.9

Investing Activities

Proceeds from Sale of Available-for-sale Securities

12.1

10.2

10.1

Payments for Purchase of Available-for-sale Securities

(12.2)

(13.3)

(8.6)

Acquisitions of Subsidiaries – Net of Cash and Restricted Cash Acquired

0.0

(18.5)

Equity Investments

(37.9)

(39.2)

(7.8)

Proceeds from Equity Method Investment, Distribution, Return of Capital

8.3

0.0

Additions to Property, Plant and Equipment

(597.1)

(312.4)

(208.5)

Proceeds from Sale of Productive Assets

268.6

0.0

Other Investing Activities

12.9

5.7

4.3

Cash for Investing Activities

(345.3)

(349.0)

(229.0)

Financing Activities

Proceeds from Issuance of Common Stock

1.9

20.3

86.0

Proceeds from Issuance of Long-Term Debt

201.9

75.6

131.5

Repayments of Long-Term Debt

(72.2)

(95.5)

(189.6)

Proceeds from Non-Controlling Interest

103.8

0.0

(3.8)

0.0

(19.7)

Dividends on Common Stock

(121.4)

(115.0)

(108.7)

Other Financing Activities

(0.9)

(0.6)

(1.6)

Cash for Financing Activities

109.3

(115.2)

(102.1)

Change in Cash, Cash Equivalents and Restricted Cash

13.5

(31.1)

71.8

Cash, Cash Equivalents and Restricted Cash

$ 92.5

$ 79.0

$ 110.1

[1]	(a) Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019. (See Note 7. Fair Value.)

Consolidated Statement of Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Accumulated Other Comprehensive Loss [Member]	Retained Earnings [Member]	Non-Controlling Interest in Subsidiaries [Member]
Consolidated Statement of Equity [Roll Forward]
Adjustments to Opening Balance – Net of Income Taxes (a)			$ 0.0	$ 0.0
Balance, Beginning of Period at Dec. 31, 2016		$ 1,295.3	(28.2)	625.9	$ 0.0
Consolidated Statement of Equity [Roll Forward]
Common Stock Issued		106.1
Unrealized Gain (Loss) on Securities	$ 0.9		0.9
Defined Benefit Pension and Other Postretirement Plans	4.7		4.7
Net Income	172.2			172.2	0.0
Common Stock Dividends	108.7			(108.7)
Proceeds from Noncontrolling Interests	0.0
Balance, Ending of Period at Dec. 31, 2017	$ 2,068.2	1,401.4	(22.6)	689.4	0.0
Consolidated Statement of Equity [Roll Forward]
Dividends Per Share of Common Stock	$ 2.14
Adjustments to Opening Balance – Net of Income Taxes (a)			(5.6)	6.1
Common Stock Issued		27.1
Unrealized Gain (Loss) on Securities	$ (0.1)		(0.1)
Defined Benefit Pension and Other Postretirement Plans	1.0		1.0
Net Income	174.1			174.1	0.0
Common Stock Dividends	115.0			(115.0)
Proceeds from Noncontrolling Interests	0.0
Balance, Ending of Period at Dec. 31, 2018	$ 2,155.8	1,428.5	(27.3)	754.6	0.0
Consolidated Statement of Equity [Roll Forward]
Dividends Per Share of Common Stock	$ 2.24
Adjustments to Opening Balance – Net of Income Taxes (a)			0.0	0.0
Common Stock Issued		8.2
Unrealized Gain (Loss) on Securities	$ 0.2		0.2
Defined Benefit Pension and Other Postretirement Plans	3.5		3.5
Net Income	185.5			185.6	(0.1)
Common Stock Dividends	121.4			(121.4)
Proceeds from Noncontrolling Interests	(103.8)
Balance, Ending of Period at Dec. 31, 2019	$ 2,335.6	$ 1,436.7	$ (23.6)	$ 818.8	$ 103.7
Consolidated Statement of Equity [Roll Forward]
Dividends Per Share of Common Stock	$ 2.35

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in five states, approximately 660 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 380 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

U.S. Water Services provided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. On March 26, 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

BNI Energy mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2019, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 9. Commitments, Guarantees and Contingencies.)

Our investment in Nobles 2 represents 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.

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

Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. As of December 31, 2019, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement. In prior periods presented, the amounts also include U.S. Water Services' standby letters of credit. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under an ALLETE Clean Energy loan agreement, PSAs and a tax equity financing agreement. In prior periods presented, the amounts also include deposits from a SWL&P customer in aid of future capital expenditures. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amounts presented in the Consolidated Statement of Cash Flows.



Cash, Cash Equivalents and Restricted Cash	December 31, 2019		December 31, 2018		December 31, 2017
Millions
Cash and Cash Equivalents		$69.3		$69.1		$98.9
Restricted Cash included in Prepayments and Other	2.8		1.3		2.6
Restricted Cash included in Other Non-Current Assets	20.4		8.6		8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		$92.5		$79.0		$110.1

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flow Information.



Consolidated Statement of Cash Flows
Year Ended December 31	2019		2018		2017
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$63.5		$66.0		$64.5
Recognition of Right-of-use Assets and Lease Liabilities (a)		$28.7	—		—
Remeasurement of Deferred Income Taxes Resulting from the TCJA
Increase in Regulatory Assets	—		—			$80.9
Decrease in Investment in ATC	—		—		$(27.9)
Decrease in Deferred Income Taxes	—		—		$(353.6)
Increase in Regulatory Liabilities	—		—			$393.6
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$33.9		$(0.1)		$67.2
Reclassification of Property, Plant and Equipment to Inventory (b)	—			$46.3	—
Capitalized Asset Retirement Costs	$20.7		$14.2		$(15.6)
AFUDC–Equity		$2.3		$1.2		$1.2
ALLETE Common Stock Contributed to Pension Plans	—		—			$13.5


(a)	See Leases.

(b)

In February 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification from Property, Plant and Equipment – Net to Inventories – Net for project costs incurred in the prior year. On the Consolidated Statement of Cash Flows, the sale of the wind energy facility in the fourth quarter of 2018 resulted in Operating Activities – Inventories increasing by $46.3 million in 2018 due to the project costs incurred in the prior year.

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



Accounts Receivable
As of December 31	2019		2018
Millions
Trade Accounts Receivable (a)
Billed		$77.2		$121.7
Unbilled	20.1		24.4
Less: Allowance for Doubtful Accounts	0.9		1.7
Total Accounts Receivable		$96.4		$144.4


(a)	On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related accounts receivable from the Consolidated Balance Sheet.

Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to eight Large Power Customers. Receivables from these customers totaled $7.8 million as of December 31, 2019 ($11.7 million as of December 31, 2018). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. One of these customers accounted for 12 percent of consolidated operating revenue in 2019 (10 percent in 2018 and 2017).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

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

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



Inventories – Net
As of December 31	2019		2018
Millions
Fuel (a)		$25.9		$26.0
Materials and Supplies	46.9		44.2
Raw Materials (b)	—		2.8
Work in Progress (b)	—		6.1
Finished Goods (b)	—		8.4
Reserve for Obsolescence (b)	—		(0.8		)
Total Inventories – Net		$72.8		$86.7


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

(b) On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related inventory items from the Consolidated Balance Sheet.

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

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. In 2015, Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to operate on natural gas. Minnesota Power’s 2015 IRP contained steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in 2016, and the ceasing of coal-fired operations at Taconite Harbor in 2020. (See Note 4. Regulatory Matters.) The MPUC order for the 2015 IRP also directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. As part of the 2016 general retail rate case, the MPUC allowed recovery of the remaining book value of Boswell Units 1 and 2 through 2022. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2 or the conversion of Laskin to operate on natural gas. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

ALLETE Clean Energy Asset Acquisition. On May 3, 2019, ALLETE Clean Energy acquired the Diamond Spring wind project in Oklahoma from Apex Clean Energy. ALLETE Clean Energy will build, own and operate the approximately 300 MW wind energy facility. The Diamond Spring wind project is fully contracted to sell wind power under long-term power sales agreements. Construction is expected to be completed in late 2020.

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

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

In 2019, 2018, and 2017, there were no indicators of impairment for our property, plant, and equipment or land inventory. As a result, no impairment was recorded in 2019, 2018 or 2017.

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings.

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 13. Employee Stock and Incentive Plans.)



Other Non-Current Assets
As of December 31	2019		2018
Millions
Contract Assets (a)		$28.0		$30.7
Finance Receivable (b)	—		10.4
Operating Lease Right-of-use Assets (c)	28.6		—
ALLETE Properties	21.9		24.4
Restricted Cash	20.4		8.6
Other Postretirement Benefit Plans	37.5		0.4
Other	80.8		77.9
Total Other Non-Current Assets		$217.2		$152.4


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


(b)	Finance Receivable related to the 2016 sale of Ormond Crossings and Lake Swamp, which was collected in the second quarter of 2019.


(c)	See Leases.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Current Liabilities
As of December 31	2019		2018
Millions
Provision for Interim Rate Refund (a)	—			$40.0
PSAs		$12.3	12.6
Contract Liabilities (b)	—		7.6
Provision for Tax Reform Refund (c)	0.2		10.7
Contingent Consideration (d)	—		3.8
Operating Lease Liabilities (e)	6.9		—
Other	41.0		53.8
Total Other Current Liabilities		$60.4		$128.5

(a) Provision for Interim Rate Refund was refunded to Minnesota Power’s retail customers in the second quarter of 2019.


(b)	Contract Liabilities consist of deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.


(c)	Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020.


(d)	Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019.


(e)	See Leases.



Other Non-Current Liabilities
As of December 31	2019		2018
Millions
Asset Retirement Obligation		$160.3		$138.6
PSAs	64.6		76.9
Operating Lease Liabilities (a)	21.8		—
Other	46.3		47.1
Total Other Non-Current Liabilities		$293.0		$262.6


(a)	See Leases.

Leases.

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

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

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Leases (Continued)

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

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



	December 31, 2019
Millions
Operating Lease Cost		$9.4

Other Information:
Operating Cash Flows From Operating Leases		$9.4

Additional information related to leases was as follows:



	December 31, 2019
Millions
Balance Sheet Information Related to Leases:
Other Non-Current Assets		$28.6
Total Operating Lease Right-of-use Assets		$28.6

Other Current Liabilities		$6.9
Other Non-Current Liabilities	21.8
Total Operating Lease Liabilities		$28.7

Weighted Average Remaining Lease Term (Years):
Operating Leases - Vehicles and Equipment	4
Operating Leases - Land and Other	28

Weighted Average Discount Rate:
Operating Leases - Vehicles and Equipment	3.7		%
Operating Leases - Land and Other	4.1		%

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Leases (Continued)

Maturities of lease liabilities were as follows:



	December 31, 2019
Millions
2020		$6.6
2021	6.0
2022	5.0
2023	3.2
2024	2.9
Thereafter	11.5
Total Lease Payments Due	35.2
Less: Imputed Interest	6.5
Total Lease Obligations	28.7
Less: Current Lease Obligations	6.9
Total Long-term Lease Obligations		$21.8

Environmental Liabilities. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. (See Note 9. Commitments, Guarantees and Contingencies.)

Revenue.

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

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

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

Revenue Recognition

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Nature of Revenue Streams

Utility

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

Municipal includes sales to 15 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. All wholesale electric contracts include a termination clause requiring a three-year notice to terminate. These contracts have termination dates ranging through at least 2032, with a majority of contracts effective through at least 2024. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon municipal substation or meter.

Industrial includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 54 percent of total regulated utility kWh sales for the year ended December 31, 2019. Within industrial revenue, Minnesota Power has eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. These contracts automatically renew past the contract term unless a four-year advanced written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2023 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $55 million per annum in 2020 through 2023, $20 million in 2024, and $65 million in total thereafter, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts.

Other Power Suppliers includes the sale of energy under long-term PSAs with two customers as well as MISO market and liquidation sales. Expiration dates of these PSAs range from 2020 through 2028. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon delivery point defined in the contract (generally the MISO pricing node). Based on current contracts with two customers, we expect to recognize minimum revenue for fixed contract components of approximately $3 million in 2020. Other power supplier contracts that extend beyond 2020 contain variable pricing components that prevent us from estimating future minimum revenue, and therefore are not included.

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

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Non-utility

ALLETE Clean Energy

Long-term PSA revenue includes all sales recognized under long-term contracts for production, curtailment, capacity and associated renewable energy credits from ALLETE Clean Energy wind energy facilities. Expiration dates of these PSAs range from 2020 through 2039. Performance obligations for these contracts are satisfied at the time energy is delivered to an agreed upon point, or production is curtailed at the request of the customer, at specified prices. Revenue from the sale of renewable energy credits is recognized at the same time the related energy is delivered to the customer when sold to the same party.

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

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

U.S. Water Services

Point-in-time revenue is recognized for purchases by customers for chemicals, consumable equipment (e.g., filters, pumps and valves) or related maintenance and repair services as the customer’s usage and needs change over time. These goods and services are purchased on an as-needed basis by customers and therefore revenue can be variable. Products are shipped to customers in accordance with the terms of each purchase order, and performance obligations are satisfied at the time of shipment of goods or when services are rendered to the customer.

Contract includes monthly revenue from contracts with customers to provide chemicals, consumable equipment and services to meet customer needs during the contract period. As agreed with the customer, a fixed amount is invoiced based on the goods and services to be provided under the contract. The duration of these contracts generally range in length from three months to five years and automatically renew. A 30-day notice is required to terminate such contracts without penalty. Performance obligations are satisfied during the period as goods and service are delivered in accordance with the terms of the contract.

Capital Project includes the sale of equipment and other components assembled to create a water treatment system for a customer. These projects are provided under contracts at an agreed upon price to meet a customer's specifications and typically take less than one year to complete. In general, progress payments are received throughout the project period and are recorded as contract liabilities until performance obligations are satisfied at the time the equipment and other components are delivered to the customer’s site.

Corporate and Other

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

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Payment Terms

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

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

We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2019, we have $28.0 million of assets recognized for costs incurred to obtain contracts with our customers ($30.7 million as of December 31, 2018). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $2.6 million of non-cash amortization for the years ended December 31, 2019 and 2018.



Operating Expenses – Other
Year Ended December 31	2019	2018	2017
Millions
Change in Fair Value of Contingent Consideration (a)	—	$(2.0)	$(0.7)
Total Operating Expenses – Other	—	$(2.0)	$(0.7)


(a)	Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019. (See Note 7. Fair Value.)

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

Tax Equity Financings. In the fourth quarter of 2019, certain subsidiaries of ALLETE entered into tax equity financings that include forming limited liability companies (LLC) with third-party investors for certain wind projects. Tax equity financings have specific terms that dictate distributions of cash and the allocation of tax attributes among the partners, who are divided into two categories: the sponsor and third-party investor. ALLETE subsidiaries are the sponsors in these tax equity financings. The distributions of cash and allocation of tax attributes in these financings are generally different than the underlying percentage ownership interests in the related LLC. A disproportionate share of tax attributes (including accelerated depreciation and production tax credits) are allocated to third-party investors in order to achieve targeted after-tax rates of return, or target yield, from project operations, while a disproportionate share of cash distributions are made to the sponsor.

The target yield and terms vary by financing agreement, by third-party investor, and sponsor project. Once the third-party investor’s target yield has been achieved, a “flip point” is recognized. Prior to the flip point, tax attributes are disproportionately allocated to the third-party investor with cash distributions disproportionately made to the sponsor. In addition, cash distributions can be temporarily increased to the third-party investors in order to meet cumulative distribution thresholds. After the flip point, tax attributes and cash distributions are both typically disproportionately allocated to the sponsor.

Tax equity financings impose a range of affirmative and negative covenants that are similar to what a project lender would require, such as financial reporting, insurance, maintenance and prudent operator standards. Most of these restrictions end once the flip point occurs and any other obligations of the third-party investor have been eliminated.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Tax Equity Financings (Continued)

The third-party investor’s portion of equity ownership in tax equity LLC is recorded as non-controlling interest in subsidiaries on the Consolidated Balance Sheet.

Non-Controlling Interest in Subsidiaries. Non-controlling interest in subsidiaries represents the portion of equity ownership, net income (loss), and comprehensive income (loss) in subsidiaries that is not attributable to equity holders of ALLETE.

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

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

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

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



Other Income (Expense) - Other
Year Ended December 31	2019		2018		2017
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credit (a)		$7.7		$4.6		$3.9
Interest and Investment Earnings	4.4		0.5		1.8
AFUDC - Equity	2.3		1.2		1.2
Gain (Loss) on Land Sales	2.1		0.9		(0.5		)
Other	2.2		0.6		(0.1		)
Total Other Income (Expense) - Other		$18.7		$7.8		$6.3


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

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

Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with GAAP for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more‑likely‑than‑not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more‑likely‑than‑not” means more than 50 percent likely. (See Note 11. Income Tax Expense.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

New Accounting Pronouncements.

Recently Adopted Pronouncements

Disclosure Update and Simplification. In November 2018, the SEC adopted amendments to certain disclosure requirements. The amendments adopted include requirements that interim financial statements should include comparative statements for the same period in the prior financial year, except that the requirement for comparative balance sheet information may be satisfied by presenting the year-end balance sheet. It further includes a requirement analyzing the changes in each caption of shareholders’ equity either separately in a note or on the face of the financial statement. These amendments were effective for ALLETE in the first quarter of 2019. We have included the presentation of our Statement of Shareholders’ Equity to meet these requirements.

Leases. In 2016, the FASB issued an accounting standard update which revised the existing guidance for leases. Under the revised guidance, lessees are required to recognize right-of-use assets and lease liabilities on the Consolidated Balance Sheet for leases with terms greater than 12 months. The new standard also requires additional qualitative and quantitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement and presentation of expenses and cash flows from leases is not expected to significantly change as a result of the new guidance. The Company adopted this guidance in the first quarter of 2019 using the optional transition method and the package of practical expedients, which allowed for the adoption of the standard as of January 1, 2019, without restating previously disclosed information. Management elected the optional transition method of adoption due to the overall immateriality of the balance sheet gross up in the period of adoption. The package of practical expedients allowed management to not reassess the lease classification for leases, including those that had expired during the periods presented or that still existed at the time of adoption. We have included additional disclosures in the notes to the consolidated financial statements.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2019			2018
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,555.8			$4,490.6
Construction Work in Progress	383.6			251.1
Accumulated Depreciation	(1,635.3		)	(1,549.6		)
Regulated Operations – Net	3,304.1			3,192.1
ALLETE Clean Energy
Property, Plant and Equipment in Service	686.0			488.4
Construction Work in Progress	351.3			164.5
Accumulated Depreciation	(86.8		)	(73.0		)
ALLETE Clean Energy – Net	950.5			579.9
U.S. Water Services (a)
Property, Plant and Equipment in Service	—			30.1
Accumulated Depreciation	—			(14.0		)
U.S. Water Services – Net	—			16.1
Corporate and Other (b)
Property, Plant and Equipment in Service	231.9			214.3
Construction Work in Progress	3.8			6.6
Accumulated Depreciation	(113.3		)	(104.6		)
Corporate and Other – Net	122.4			116.3
Property, Plant and Equipment – Net		$4,377.0			$3,904.4


(a)	On March 26, 2019, ALLETE completed the sale of U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)


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

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



Estimated Useful Lives of Property, Plant and Equipment (Years)
Regulated Operations
Generation	4 to 50	ALLETE Clean Energy	5 to 35
Transmission	52 to 71	Corporate and Other	3 to 50
Distribution	19 to 68

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

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

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

NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)



Asset Retirement Obligations
Millions
Obligation as of December 31, 2017		$122.7
Accretion	7.0
Liabilities Settled	(5.3		)
Revisions in Estimated Cash Flows	14.2
Obligation as of December 31, 2018	138.6
Accretion	7.2
Liabilities Recognized	1.4
Liabilities Settled	(4.6		)
Revisions in Estimated Cash Flows	17.7
Obligation as of December 31, 2019		$160.3

Regulatory Matters

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $31.8 million in 2019 ($103.8 million in 2018; $96.9 million in 2017). With the implementation of final rates in Minnesota Power’s general rate case, certain revenue previously recognized under cost recovery riders was incorporated into base rates. (See 2016 Minnesota General Rate Case.)

2016 Minnesota General Rate Case. The MPUC issued a March 2018 order 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 results in additional revenue of approximately $13 million on an annualized basis.

2020 Minnesota General Rate Case. On November 1, 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing seeks a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $66 million in additional revenue. In orders dated December 23, 2019, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $36.1 million beginning January 1, 2020.

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

Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through at least December 31, 2032. No termination notice may be given for this contract prior to July 1, 2029. The wholesale electric service contract with SWL&P is effective through at least February 28, 2023. Under the agreement with SWL&P, no termination notice has been given. The rates included in these two contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.

Minnesota Power’s wholesale electric contracts with 14 municipal customers are effective through varying dates ranging from 2024 through 2029. No termination notices may be given prior to three years before maturity. These contracts had fixed capacity charges through 2018; beginning in 2019, the capacity charge is determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term is set each January 1, subject to monthly adjustment, and is determined using a cost-based formula methodology.

The contract with another municipal customer expired on June 30, 2019. Minnesota Power historically provided approximately 29 MW of average monthly demand to this customer.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates allowing Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. On July 9, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor to include investments made for the GNTL. (See Note 9. Commitments, Guarantees and Contingencies.)

Renewable Cost Recovery Rider. 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. Current customer billing rates for the renewable cost recovery rider were approved by the MPUC in a November 2018 order. On August 15, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor.

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

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a November 2018 order.

Fuel Adjustment Clause Reform. In a 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. With this order, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On May 1, 2019, Minnesota Power filed its fuel adjustment forecast for 2020, which was accepted by the MPUC in an order dated November 14, 2019, for purposes of setting fuel adjustment clause rates for 2020, subject to a true-up filing in 2021.

2018 Wisconsin General Rate Case. In a December 2018 order, 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 resulted in additional revenue of approximately $3 million.

Integrated Resource Plan. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2 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 requests for proposal for additional wind, solar and demand response resource additions. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. Minnesota Power’s next IRP filing is due October 1, 2020.

In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of a PPA for the output of a 250 MW wind energy facility as well as approval of a 250 MW natural gas capacity dedication agreement. The natural gas capacity dedication agreement was subject to MPUC approval of the construction of NTEC, a 525 MW to 625 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, as well as a securitization plan. On December 23, 2019, the Minnesota Court of Appeals reversed and remanded the MPUC’s decision to approve certain affiliated-interest agreements. The MPUC was ordered to determine whether NTEC may have the potential for significant environmental effects and, if so, to prepare an environmental assessment worksheet before reassessing the agreements. On January 22, 2020, Minnesota Power filed a petition for further review with the Minnesota Supreme Court requesting that it review and overturn the Minnesota Court of Appeals decision. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW, which was approved by the PSCW at a hearing on January 16, 2020. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $700 million, of which ALLETE’s portion is expected to be approximately $350 million. ALLETE’s portion of NTEC project costs incurred through December 31, 2019, is approximately $12 million.

In August 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.)

Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on energy CIPs each year. In 2017, the Minnesota Department of Commerce approved Minnesota Power’s modified CIP triennial filing for 2017 through 2019, which outlined Minnesota Power’s CIP spending and energy-saving goals for those years. Minnesota Power’s CIP investment goal was $10.5 million for 2019 ($10.3 million for 2018 and 2017), with actual spending of $8.3 million in 2019 ($9.0 million in 2018; $8.1 million in 2017). The investment goal for 2020 is $10.5 million based on approval of an extension for Minnesota Power’s next CIP triennial filing by the Minnesota Department of Commerce on November 26, 2019.

NOTE 4. REGULATORY MATTERS (Continued)

Conservation Improvement Program (Continued)

On April 1, 2019, Minnesota Power submitted its 2018 consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $2.8 million based upon MPUC procedures, which was approved by the MPUC in an order dated July 19, 2019. In 2018, the CIP financial incentive of $3.0 million was recognized in the third quarter upon approval by the MPUC of Minnesota Power’s 2017 CIP consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

MISO Return on Equity Complaint. MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of 9.88 percent, or 10.38 percent including an incentive adder for participation in a regional transmission organization, based on a November 2019 FERC order. In this order, the FERC reduced the base return on equity for regional transmission organizations as recommended by an administrative law judge with refunds ordered for prior periods, which are immaterial to ALLETE. Multiple parties to the complaint have appealed the FERC order.

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.

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. Minnesota Power expects that Camp Ripley, the community solar garden arrays, and an increase in solar rebates will allow Minnesota Power to meet both parts of the solar mandate.

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

NOTE 4. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2019		2018
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (a)		$212.9		$218.5
Income Taxes (b)	123.4		105.5
Asset Retirement Obligations (c)	32.0		32.6
Cost Recovery Riders (d)	24.7		—
Boswell 1 & 2 Net Plant and Equipment (e)	10.7		16.3
Manufactured Gas Plant (f)	8.2		8.0
PPACA Income Tax Deferral	4.8		5.0
Other	3.8		3.6
Total Non-Current Regulatory Assets		$420.5		$389.5
Current Regulatory Liabilities (g)
Provision for Interim Rate Refund (h)	—			$40.0
Provision for Tax Reform Refund (i)		$0.2	10.7
Transmission Formula Rates	1.7		4.4
Total Current Regulatory Liabilities	1.9		55.1
Non-Current Regulatory Liabilities
Income Taxes (b)	407.2		396.4
Wholesale and Retail Contra AFUDC (j)	79.3		64.4
Plant Removal Obligations (k)	35.5		25.1
Defined Benefit Pension and Other Postretirement Benefit Plans (a)	17.0		—
North Dakota Investment Tax Credits (l)	12.3		14.7
Conservation Improvement Program (m)	5.4		1.5
Cost Recovery Riders (d)	—		6.9
Transmission Formula Rates	—		1.6
Other	3.6		1.5
Total Non-Current Regulatory Liabilities	560.3		512.1
Total Regulatory Liabilities		$562.2		$567.2

(a)

Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)


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


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

(d)

The cost recovery rider regulatory assets and liabilities are revenue not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL. The cost recovery rider regulatory assets as of December 31, 2019, will be recovered within the next two years.


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


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


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


(h)	This amount was refunded to Minnesota Power’s regulated retail customers in the second quarter of 2019.


(i)	Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020.


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


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


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

(m)

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

Equity Investments

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Equity Investments [Text Block]

EQUITY INVESTMENTS

Investment in ATC. Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. For the year ended December 31, 2019, we invested $6.6 million in ATC and on January 31, 2020, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $2.7 million in 2020.



ALLETE’s Investment in ATC
Year Ended December 31	2019			2018
Millions
Equity Investment Beginning Balance		$128.1			$118.7
Cash Investments	6.6			6.2
Equity in ATC Earnings	21.7			17.5
Distributed ATC Earnings	(16.1		)	(15.2		)
Amortization of the Remeasurement of Deferred Income Taxes	1.3			0.9
Equity Investment Ending Balance		$141.6			$128.1



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2019		2018
Millions
Current Assets		$84.6		$87.2
Non-Current Assets	5,244.3		4,928.8
Total Assets		$5,328.9		$5,016.0
Current Liabilities		$502.6		$640.0
Long-Term Debt	2,312.8		2,014.0
Other Non-Current Liabilities	298.9		295.3
Members’ Equity	2,214.6		2,066.7
Total Liabilities and Members’ Equity		$5,328.9		$5,016.0



Income Statement Data
Year Ended December 31	2019		2018		2017
Millions
Revenue		$744.4		$690.5		$721.6
Operating Expense	373.5		358.7		344.9
Other Expense	110.5		108.3		104.1
Net Income		$260.4		$223.5		$272.6
ALLETE’s Equity in Net Income		$21.7		$17.5		$22.5

ATC’s authorized return on equity is 9.88 percent, or 10.38 percent including an incentive adder for participation in a regional transmission organization, based on a November 2019 FERC order. (See Note 4. Regulatory Matters.)

NOTE 5. EQUITY INVESTMENTS (Continued)

Investment in Nobles 2. In December 2018, our wholly-owned subsidiary, ALLETE South Wind, entered into an 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. In the fourth quarter of 2019, we entered into a tax equity funding agreement to finance up to $125 million of the project costs. We account for our investment in Nobles 2 under the equity method of accounting. As of December 31, 2019, our equity investment in Nobles 2 was $56.0 million ($33.0 million at December 31, 2018). In the first quarter of 2019, Nobles 2 returned capital of $8.3 million based on its cash needs. For the year ended December 31, 2019, we invested $31.3 million in Nobles 2. We expect to invest approximately $115 million in 2020.

Fair Value

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value [Text Block]

FAIR VALUE

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

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

NOTE 7. FAIR VALUE (Continued)

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

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

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019, and December 31, 2018. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.



	Fair Value as of December 31, 2019
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$11.1	—		—		$11.1
Available-for-sale – Corporate and Governmental Debt Securities (b)	—			$9.7	—	9.7
Cash Equivalents	0.9		—		—	0.9
Total Fair Value of Assets		$12.0		$9.7	—		$21.7

Liabilities:
Deferred Compensation (c)	—			$21.2	—		$21.2
Total Fair Value of Liabilities	—			$21.2	—		$21.2
Total Net Fair Value of Assets (Liabilities)		$12.0	$(11.5)		—	$0.5


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


(b)	As of December 31, 2019, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $2.1 million, in one year to less than three years was $7.2 million, in three years to less than five years was zero and in five or more years was $0.4 million.


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

NOTE 7. FAIR VALUE (Continued)



	Fair Value as of December 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$12.2	—		—			$12.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.0	—		8.0
Cash Equivalents	1.0		—		—		1.0
Total Fair Value of Assets		$13.2		$8.0	—			$21.2

Liabilities: (b)
Deferred Compensation	—			$19.8	—			$19.8
U.S. Water Services Contingent Consideration	—		—			$3.8	3.8
Total Fair Value of Liabilities	—			$19.8		$3.8		$23.6
Total Net Fair Value of Assets (Liabilities)		$13.2	$(11.8)		$(3.8)		$(2.4)


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


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

The Level 3 liability in the preceding table is related to the contingent consideration liability that resulted from the 2015 acquisition of U.S. Water Services. Based on the terms and conditions of the acquisition agreement, a final payout of $3.8 million was made in the first quarter of 2019.

The Company’s policy is to recognize transfers in and transfers out of Levels as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 2019 and 2018, there were no transfers in or out of Levels 1, 2 or 3.

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



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
December 31, 2019	$1,622.6	$1,791.8
December 31, 2018	$1,495.2	$1,534.6

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

Equity Method Investments. The aggregate carrying amount of our equity investments was $197.6 million as of December 31, 2019 ($161.1 million as of December 31, 2018). The Company assesses our equity investments in ATC and Nobles 2 for impairment whenever events or changes in circumstances indicate that the carrying amount of our investments may not be recoverable. For the years ended December 31, 2019 and 2018, there were no indicators of impairment. (See Note 5. Equity Investments.)

Property, Plant and Equipment. The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable. (See Note 1. Operations and Significant Accounting Policies.) For the years ended December 31, 2019, and 2018, there was no impairment of property, plant, and equipment.

NOTE 7. FAIR VALUE (Continued)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. In a 2016 order, the MPUC 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. As part of the 2016 general retail rate case, the MPUC allowed recovery of the remaining book value of Boswell Units 1 and 2 through 2022. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, ceasing of coal-fired operations at Taconite Harbor Units 1 and 2 or the conversion of Laskin to operate on natural gas. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives. (See Note 4. Regulatory Matters.)

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Short-Term and Long-Term Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2019, total short-term debt outstanding was $212.9 million ($57.5 million as of December 31, 2018), consisted of long-term debt due within one year and included $0.4 million of unamortized debt issuance costs.

As of December 31, 2019, we had consolidated bank lines of credit aggregating $407.0 million ($407.0 million as of December 31, 2018), most of which expire in January 2024. We had $62.0 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of December 31, 2019 ($18.4 million in standby letters of credit and no outstanding draws as of December 31, 2018).

On January 10, 2019, ALLETE entered into an amended and restated $400 million credit agreement (Credit Agreement). The Credit Agreement amended and restated ALLETE’s $400 million credit facility, which was scheduled to expire in October 2020. The Credit Agreement is unsecured, has a variable interest rate and will expire in January 2024. At ALLETE’s request and subject to certain conditions, the Credit Agreement may be increased by up to$150 million and ALLETE may make two requests to extend the maturity date, each for a one‑year extension. Advances may be used by ALLETE for general corporate purposes, to provide liquidity in support of ALLETE's commercial paper program and to issue up to $100 million in letters of credit.

Long-Term Debt. As of December 31, 2019, total long-term debt outstanding was $1,400.9 million ($1,428.5 million as of December 31, 2018) and included $8.4 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2020 is $213.3 million; $98.6 million in 2021; $88.8 million in 2022; $88.8 million in 2023; $73.5 million in 2024; and $1,059.6 million thereafter. Substantially all of our regulated electric plant is subject to the lien of the mortgages collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

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

On March 1, 2019, ALLETE issued and sold the following First Mortgage Bonds (the Bonds):



Maturity Date	Principal Amount	Interest Rate
March 1, 2029	$70 Million	4.08%
March 1, 2049	$30 Million	4.47%

ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. ALLETE used the proceeds from the sale of the Bonds to fund utility capital investment and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

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

Long-Term Debt (Continued)

On August 14, 2019, ALLETE entered into an amended and restated $110.0 million term loan agreement (Term Loan). The Term Loan is unsecured and due on August 25, 2020, and may be prepaid at any time, subject to a make-whole provision. Interest on the Term Loan is payable monthly at a rate per annum equal to LIBOR plus 1.025 percent. Proceeds from the Term Loan were used for construction-related expenditures.



Long-Term Debt
As of December 31	2019			2018
Millions
First Mortgage Bonds
8.17% Series Due 2019	—				$42.0
5.28% Series Due 2020		$35.0		35.0
2.80% Series Due 2020	40.0			40.0
4.85% Series Due 2021	15.0			15.0
3.02% Series Due 2021	60.0			60.0
3.40% Series Due 2022	75.0			75.0
6.02% Series Due 2023	75.0			75.0
3.69% Series Due 2024	60.0			60.0
4.90% Series Due 2025	30.0			30.0
5.10% Series Due 2025	30.0			30.0
3.20% Series Due 2026	75.0			75.0
5.99% Series Due 2027	60.0			60.0
3.30% Series Due 2028	40.0			40.0
4.08% Series Due 2029	70.0			—
3.74% Series Due 2029	50.0			50.0
3.86% Series Due 2030	60.0			60.0
5.69% Series Due 2036	50.0			50.0
6.00% Series Due 2040	35.0			35.0
5.82% Series Due 2040	45.0			45.0
4.08% Series Due 2042	85.0			85.0
4.21% Series Due 2043	60.0			60.0
4.95% Series Due 2044	40.0			40.0
5.05% Series Due 2044	40.0			40.0
4.39% Series Due 2044	50.0			50.0
4.07% Series Due 2048	60.0			60.0
4.47% Series Due 2049	30.0			—
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Unsecured Term Loan Variable Rate Due 2020	110.0			10.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024	47.8			57.2
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8			27.8
Senior Unsecured Notes 3.11% Due 2027	80.0			80.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0			15.0
SWL&P First Mortgage Bonds 4.14% Series Due 2048	12.0			12.0
Other Long-Term Debt, 3.11% – 5.75% Due 2020 – 2037	46.5			67.7
Unamortized Debt Issuance Costs	(8.8		)	(9.2		)
Total Long-Term Debt	1,613.8			1,486.0
Less: Due Within One Year	212.9			57.5
Net Long-Term Debt		$1,400.9			$1,428.5

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

Long-Term Debt (Continued)

On January 10, 2020, ALLETE entered into a $200 million term loan agreement (Term Loan) and borrowed $60 million upon execution. The unsecured Term Loan provides for the ability to borrow up to an additional $140 million, is due on February 10, 2021, and may be repaid at any time. Interest is payable monthly at a rate per annum equal to LIBOR plus 0.55 percent. Proceeds from the Term Loan will be used for construction-related expenditures.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of December 31, 2019, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of December 31, 2019, ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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



As of December 31, 2019
Millions	2020		2021		2022		2023		2024		Thereafter
Capital Purchase Obligations		$292.7	—		—		—		—		—
Easements (a)		$5.0		$5.3		$5.4		$5.5		$5.5		$170.4
PPAs (b)		$113.0		$122.5		$145.5		$145.6		$138.5		$1,386.7
Other Purchase Obligations (c)		$22.8		$9.6	—		—		—			$0.1


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


(b)	Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with Nobles 2 commencing in 2020 as it is subject to construction of a wind energy facility. (See Power Purchase Agreements.)

(c)

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

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

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

Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal‑fired generating unit. Minnesota Power’s output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power PSA described in the following table. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2019, Square Butte had total debt outstanding of $280.7 million. Annual debt service for Square Butte is expected to be approximately $48.7 million annually through 2023 and $33.6 million in 2024, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power’s cost of power purchased from Square Butte during 2019 was $82.7 million ($78.0 million in 2018; $75.7 million in 2017). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $8.3 million in 2019 ($9.1 million in 2018; $9.4 million in 2017). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnesota Power has also entered into the following PPAs for the purchase of capacity and energy as of December 31, 2019:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Calpine Corporation	25 MW	Capacity	June 2019	May 2026	Fixed
Great River Energy
PPA 1	50 MW	Capacity / Energy	June 2016	May 2020	(a)
PPA 2	50 MW	Capacity	June 2016	May 2020	Fixed
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
Manitoba Hydro
PPA 1	(b)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	50 MW	Capacity / Energy	June 2015	May 2020	(c)
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
PPA 4 (d)	250 MW	Capacity / Energy	June 2020	May 2035	(e)
PPA 5 (d)	133 MW	Energy	(f)	(f)	Forward Market Prices
Minnkota Power	50 MW	Capacity / Energy	June 2016	May 2020	(g)
Nobles 2 (h)	(h)	Capacity / Energy	(h)	(h)	Fixed
Oliver Wind I	(i)	Energy	December 2006	December 2040	Fixed
Oliver Wind II	(i)	Energy	December 2007	December 2040	Fixed


(a)	The capacity price is fixed and the energy price is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index, as well as market prices.


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


(c)	The capacity and energy prices are adjusted annually by the change in a governmental inflationary index.


(d)	Agreements are subject to the construction of the GNTL and MMTP. (See Great Northern Transmission Line.)


(e)	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 component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.


(f)	The contract term will be the 20-year period beginning on the in-service date for the GNTL. (See Great Northern Transmission Line.)


(g)	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.


(h)	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota for 20 years beginning upon commercial operation of the wind energy facility which is currently expected in fourth quarter of 2020. (See Note 4. Regulatory Matters and Note 5. Equity Investments.)


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

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power has also entered into the following PSAs for the sale of capacity and energy as of December 31, 2019:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(a)
PSA 2	(b)	Capacity	June 2022	May 2025	Fixed
PSA 3	100 MW	Capacity	June 2025	May 2028	Fixed
Minnkota Power	(c)	Capacity / Energy	June 2014	December 2026	(c)
Oconto Electric Cooperative	25 MW	Capacity / Energy	January 2019	May 2026	Fixed
Silver Bay Power	(d)	Energy	January 2017	December 2031	(e)


(a)	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.


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

(c)

Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2019 (28 percent in 2018 and in 2017). (See Square Butte PPA.)

(d)

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. Minnesota Power supplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power had the option to purchase additional energy from Minnesota Power as it transitioned away from self-generation. In the third quarter of 2019, Silver Bay Power ceased self-generation and Minnesota Power began supplying the full energy requirements for Silver Bay Power.

(e)

The energy pricing was fixed through 2019 with pricing in later years escalating at a fixed rate annually and adjusted for changes in a natural gas index.

Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2021. 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.

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.

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. Construction activities commenced in the first quarter of 2017, and Minnesota Power expects the GNTL to be complete and in-service by mid-2020. The total project cost in the U.S., including substation work, is estimated to be approximately $700 million, of which Minnesota Power’s portion is expected to be approximately $325 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $633.3 million have been incurred through December 31, 2019, of which $339.6 million has been recovered from a subsidiary of Manitoba Hydro.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which was received on April 4, 2019. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP, which was recommended for approval on November 15, 2018. On June 14, 2019, Manitoba Hydro announced Canada’s federal government approved the MMTP project and on August 22, 2019, the NEB granted final pre-construction approvals. Construction on the MMTP commenced in the third quarter of 2019.

The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in‑service requirements in PPAs with Minnesota Power, Manitoba Hydro had indicated that it would need to start construction of the MMTP by September 2019. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. In the event the MMTP is delayed and not in-service by June 1, 2020, Minnesota Power has construction and related agreements in place with Manitoba Hydro and a Manitoba Hydro subsidiary that will protect Minnesota Power and its customers.

Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be completely in service by early 2021.

Environmental Matters.

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

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

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

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

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the NO_x and SO₂ allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. None of the compliance costs for proposed or current NAAQS revisions are expected to be material.

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


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


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


•	Improving efficiency of our generating facilities;


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


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


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


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

EPA Regulation of GHG Emissions. On June 19, 2019, the EPA finalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units.

The EPA repealed the Clean Power Plan (CPP), following a determination by the EPA that the CPP exceeded the EPA’s statutory authority under the Clean Air Act (CAA). The primary reason for this was that the CPP attempted to regulate electric generating unit’s carbon emissions through measures outside of the affected unit’s direct control. The CPP was first announced as a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”.

With the repeal of the CPP, the Affordable Clean Energy Rule was finalized. The rule establishes emissions guidelines for states to use when developing plans to limit carbon dioxide at coal-fired power plants. The rule identifies heat rate improvements made at individual units as the best system of emission reduction. Affected facilities for Minnesota Power include Boswell Units 3 and 4 and Taconite Harbor 1 and 2. Based on our initial review of the rule, many of the candidate heat rate improvements are already installed on Boswell Units 3 and 4.

Additionally, the EPA finalized new regulations for the state implementation of the Affordable Clean Energy Rule and any future emission guidelines issued under CAA Section 111(d). States will have three years to submit State Implementation Plans (SIP), and the EPA has 12 months to review and approve those plans. Since the Affordable Clean Energy Rule allows states considerable flexibility in how to best implement its requirements, Minnesota Power plans to work closely with the MPCA and the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If a state does not submit a SIP or submits a SIP that is unacceptable to the EPA, the EPA will develop a Federal Implementation Plan.

Minnesota had already initiated several measures consistent with those called for under the now repealed CPP and finalized Affordable Clean Energy Rule. Minnesota Power continues implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 4. Regulatory Matters.) We are unable to predict the GHG emission compliance costs we might incur as a result of the Affordable Clean Energy Rule and the resulting SIP; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On November 22, 2019, the EPA published a draft rulemaking that proposes to allow re-use of bottom ash transport water in FGD scrubber systems with minor discharges related to maintaining system water balance. The proposed rulemaking would also allow future discharge of FGD wastewater discharge provided it meets new BACT standards. A final rulemaking is anticipated in mid to late 2020.

The final ELG's potential impact on Minnesota Power operations is primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not discharge to surface waters, but may do so in the future if additional water treatment measures are implemented. Under the current ELG rule, bottom ash transport water discharge to surface waters must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell to reduce the amount of water discharged and evaluate potential re‑use options in its plant processes. The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce timelines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown.

At this time, we cannot estimate what compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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

Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.

Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule includes requirements for new landfill and impoundment construction, and regulates closure activities for existing impoundments. In 2017, the EPA announced its intention to formally reconsider certain provisions of the CCR rule under Subtitle D of the RCRA and on March 15, 2018, published the first phase of the proposed rule revisions in the Federal Register. In July 2018, the EPA finalized a portion of those proposed revisions that extended certain deadlines by two years, and established alternative groundwater protection standards for certain constituents and the potential for risk‑based management options at facilities based on site characteristics. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule related to operation of clay-lined impoundments. In response to the August 2018 court decision and outstanding issues from litigation, the EPA proposed additional rule revisions in August and December 2019.

The EPA’s most recent proposed rule revisions are anticipated to be finalized in the first quarter of 2020 and could impact the timing of closure activities for Boswell’s existing clay-lined impoundments. Costs of CCR compliance at Boswell are currently estimated to be between approximately $65 million and $120 million, and are expected to occur primarily over the next 15 years. Compliance costs for CCR at Taconite Harbor and Laskin are not expected to be material given CCR units at these facilities are closed. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR‑related waters. Minnesota Power would seek recovery of additional costs through a rate proceeding.

NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Other Environmental Matters

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. In June 2019, the WDNR approved the site investigation and authorized SWL&P to transition into the remedial design process. As of December 31, 2019, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $7 million as of December 31, 2018), and an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expect to incur these costs over the next four years.

Other Matters

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 2020 and 2039. As of December 31, 2019, ALLETE Clean Energy has $64.3 million outstanding in standby letters of credit.

BNI Energy. As of December 31, 2019, BNI Energy had surety bonds outstanding of $67.7 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. BNI Energy’s total reclamation liability is currently estimated at $67.3 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of December 31, 2019, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $4.8 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $2.3 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In 2005, the Town Center District issued $26.4 million of tax-exempt, 6.0 percent capital improvement revenue bonds, and in 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in 2006 for the Town Center District and 2007 for the Palm Coast Park District. To the extent that ALLETE Properties still owns land at the time of the assessment, it will incur the cost of its portion of these assessments, based upon its ownership of benefited property.

As of December 31, 2019, we owned 53 percent of the assessable land in the Town Center District (68 percent as of December 31, 2018) and none of the assessable land in the Palm Coast Park District (19 percent as of December 31, 2018). As of December 31, 2019, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are $1.4 million for Town Center at Palm Coast. As we sell property at these projects, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

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

Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Common Stock and Earnings Per Share [Text Block]

COMMON STOCK AND EARNINGS PER SHARE



Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2016	49,560		$1,295.3
Employee Stock Purchase Plan	12	0.8
Invest Direct	257	19.0
Options and Stock Awards	22	3.6
Contributions to RSOP	50	3.5
Equity Issuance Program	1,000	65.7
Contributions to Pension	216	13.5
Balance as of December 31, 2017	51,117	1,401.4
Employee Stock Purchase Plan	11	0.8
Invest Direct	277	20.7
Options and Stock Awards	57	2.1
Contributions to RSOP	47	3.5
Balance as of December 31, 2018	51,509	1,428.5
Employee Stock Purchase Plan	8	0.7
Invest Direct	38	3.0
Options and Stock Awards	85	1.3
Contributions to RSOP	39	3.2
Balance as of December 31, 2019	51,679		$1,436.7

Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc., in 2008, as amended most recently in 2016, with respect to the issuance and sale of up to an aggregate of 13.6 million shares of our common stock, without par value, of which 2.9 million shares remain available for issuance as of December 31, 2019. For the year ended December 31, 2019, no shares of common stock were issued under this agreement (none in 2018; 1.0 million shares for net proceeds of $65.7 million in 2017). The shares issued in 2017 were offered and sold pursuant to Registration Statement No. 333-212794. On July 31, 2019, we filed Registration Statement No. 333-232905, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

Contributions to Pension. For the year ended December 31, 2019, we contributed no shares of ALLETE common stock to our pension plan (none in 2018 and 0.2 million shares, which had an aggregate value of $13.5 million in 2017). The shares of ALLETE common stock contributed in 2017 were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.

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

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



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2019
Net Income Attributable to ALLETE		$185.6			$185.6
Average Common Shares	51.6		0.1	51.7
Earnings Per Share		$3.59			$3.59
2018
Net Income Attributable to ALLETE		$174.1			$174.1
Average Common Shares	51.3		0.2	51.5
Earnings Per Share		$3.39			$3.38
2017
Net Income Attributable to ALLETE		$172.2			$172.2
Average Common Shares	50.8		0.2	51.0
Earnings Per Share		$3.39			$3.38

Income Tax Expense

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2019			2018			2017
Millions
Current Income Tax Expense (a)
Federal	—			—			—
State	$0.1			$0.3			$0.3
Total Current Income Tax Expense		$0.1			$0.3			$0.3
Deferred Income Tax Expense (Benefit)
Federal (b)	$(27.8)			$(26.2)				$12.1
Federal – Remeasurement of Deferred Income Taxes (c)	—			—			(13.0		)
State	21.7			11.0			15.8
Investment Tax Credit Amortization	(0.6		)	(0.6		)	(0.5		)
Total Deferred Income Tax Expense (Benefit)	$(6.7)			$(15.8)				$14.4
Total Income Tax Expense (Benefit)	$(6.6)			$(15.5)				$14.7

(a)

For the years ended December 31, 2019, 2018 and 2017, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. Federal and state NOLs are being carried forward to offset current and future taxable income.


(b)	For the years ended December 31, 2019, and 2018, the federal tax benefit is primarily due to production tax credits, and the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA.


(c)	For the year ended December 31, 2017, the federal deferred income tax benefit is due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

NOTE 11. INCOME TAX EXPENSE (Continued).



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2019			2018			2017
Millions
Income Before Non-Controlling Interest and Income Taxes		$178.9			$158.6			$186.9
Statutory Federal Income Tax Rate	21		%	21		%	35		%
Income Taxes Computed at Statutory Federal Rate		$37.6			$33.3			$65.4
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	17.2			8.9			10.5
Production Tax Credits	(50.7		)	(45.0		)	(45.1		)
Regulatory Differences – Excess Deferred Tax Benefit (a)	(8.8		)	(8.2		)	1.2
U.S. Water Services Sale of Stock Basis Difference	1.7			—			—
Change in Fair Value of Contingent Consideration	—			(0.4		)	—
Remeasurement of Deferred Income Taxes (b)	—			—			(13.0		)
Other	(3.6		)	(4.1		)	(4.3		)
Total Income Tax Expense (Benefit)		($6.6	)		($15.5	)		$14.7


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


(b)	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

The effective tax rate was a benefit of 3.7 percent for 2019 (benefit of 9.8 percent for 2018; expense of 7.9 percent for 2017). The 2019 effective tax rate was primarily impacted by production tax credits and the gain on sale of U.S. Water Services. The 2018 effective tax rate was primarily impacted by production tax credits and the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA. The 2017 effective tax rate was primarily impacted by production tax credits and the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.



Deferred Income Tax Assets and Liabilities
As of December 31	2019			2018
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation		$49.9			$62.2
Property-Related	76.9			95.2
NOL Carryforwards	63.2			86.1
Tax Credit Carryforwards	395.5			349.8
Power Sales Agreements	23.7			27.5
Regulatory Liabilities	116.9			113.4
Other	23.4			25.1
Gross Deferred Income Tax Assets	749.5			759.3
Deferred Income Tax Asset Valuation Allowance	(70.0		)	(66.5		)
Total Deferred Income Tax Assets		$679.5			$692.8
Deferred Income Tax Liabilities
Property-Related		$713.4			$752.5
Regulatory Asset for Benefit Obligations	54.5			61.0
Unamortized Investment Tax Credits	31.6			32.2
Partnership Basis Differences	49.4			40.8
Regulatory Assets	35.4			29.9
Other	8.0			—
Total Deferred Income Tax Liabilities		$892.3			$916.4
Net Deferred Income Taxes (a)		$212.8			$223.6


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

NOTE 11. INCOME TAX EXPENSE (Continued).



NOL and Tax Credit Carryforwards
As of December 31	2019	2018
Millions
Federal NOL Carryforwards (a)	$211.3		$319.0
Federal Tax Credit Carryforwards	$302.5	$256.4
State NOL Carryforwards (a)	$274.8	$305.8
State Tax Credit Carryforwards (b)	$23.4	$27.4


(a)	Pre-tax amounts.


(b)	Net of a $69.6 million valuation allowance as of December 31, 2019 ($66.0 million as of December 31, 2018).

The federal NOL and tax credit carryforward periods expire between 2031 and 2039. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore, no federal valuation allowance has been recognized as of December 31, 2019. The state NOL and tax credit carryforward periods expire between 2024 and 2045. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.



Gross Unrecognized Income Tax Benefits	2019			2018			2017
Millions
Balance at January 1		$1.6			$1.7			$2.0
Additions for Tax Positions Related to the Current Year	0.1			0.1			0.1
Additions for Tax Positions Related to Prior Years	0.1			0.1			0.1
Reductions for Tax Positions Related to Prior Years	(0.4		)	(0.2		)	(0.1		)
Lapse of Statute	—			(0.1		)	(0.4		)
Balance as of December 31		$1.4			$1.6			$1.7

Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The gross unrecognized tax benefits as of December 31, 2019, included $0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2019, we had no accrued interest (none as of December 31, 2018, and 2017) related to unrecognized tax benefits included on the Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income. Interest expense related to unrecognized tax benefits on the Consolidated Statement of Income was immaterial in 2019, 2018 and 2017). There were no penalties recognized in 2019, 2018 or 2017. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

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

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has no open federal or state audits, and is no longer subject to federal examination for years before 2016 or state examination for years before 2015.

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union, non-union and combined retiree defined benefit pension plans covering eligible employees. The combined retiree defined benefit pension plan was created in 2016, to include all union and non-union retirees from the existing plans as of January 1, 2016. The plans provide defined benefits based on years of service and final average pay. We contributed $10.4 million in cash to the plans in 2019 ($15.0 million in 2018; $1.7 million in 2017). We contributed no shares of ALLETE common stock to the plans in 2019 (none in 2018; 0.2 million shares, which had an aggregate value of $13.5 million in 2017). We also have a defined contribution RSOP covering substantially all employees. The 2019 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $10.8 million ($11.4 million for the 2018 plan year; $11.0 million for the 2017 plan year). (See Note 10. Common Stock and Earnings Per Share and Note 13. Employee Stock and Incentive Plans.)

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

We have postretirement health care and life insurance plans covering eligible employees. In 2010, the postretirement health care plan was closed to employees hired after January 31, 2011, and the eligibility requirements were amended. In 2014, the postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015, and in 2018, the postretirement life plan was amended to limit the benefit level for union employees retiring after December 31, 2018. The postretirement health and life plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In 2019, no contributions were made to the VEBAs (none in 2018; none in 2017) and no contributions were made to the grantor trusts (none in 2018; none in 2017).

Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the pension plans. Contributions are based on estimates and assumptions which are subject to change. On January 15, 2020, we contributed $10.7 million in cash to the defined benefit pension plans. We do not expect to make any additional contributions to the defined benefit pension plans in 2020, and we do not expect to make any contributions to the defined benefit postretirement health and life plans in 2020.

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

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

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



Pension Obligation and Funded Status
As of December 31	2019			2018
Millions
Accumulated Benefit Obligation		$812.0			$713.7
Change in Benefit Obligation
Obligation, Beginning of Year		$747.0			$793.2
Service Cost	9.3			11.0
Interest Cost	31.9			29.6
Plan Amendments	—			(1.5		)
Plan Curtailments	—			(6.9		)
Actuarial (Gain) Loss	98.3			(53.0		)
Benefits Paid	(53.4		)	(49.5		)
Participant Contributions	20.9			24.1
Obligation, End of Year		$854.0			$747.0
Change in Plan Assets
Fair Value, Beginning of Year		$598.0			$628.2
Actual Return on Plan Assets	122.1			(21.2		)
Employer Contribution (a)	32.9			40.5
Benefits Paid	(53.4		)	(49.5		)
Fair Value, End of Year		$699.6			$598.0
Funded Status, End of Year	$(154.4)			$(149.0)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.6)			$(1.6)
Non-Current Liabilities	$(152.8)			$(147.4)


(a)	Includes Participant Contributions noted above.

The pension costs that are reported as a component within the Consolidated Balance Sheet, reflected in long-term regulatory assets or liabilities and accumulated other comprehensive income, consist of a net loss of $243.4 million and prior service credit of $1.3 million as of December 31, 2019 (net loss of $230.5 million and prior service credit of $1.4 million as of December 31, 2018).



Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2019	2018
Millions
Net Loss	$(243.4)	$(230.5)
Prior Service Credit	1.3	1.4
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	87.7	80.1
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(154.4)	$(149.0)

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



Components of Net Periodic Pension Cost
Year Ended December 31	2019			2018			2017
Millions
Service Cost		$9.3			$11.0			$10.2
Non-Service Cost Components (a)
Interest Cost	31.9			29.6			32.5
Expected Return on Plan Assets	(44.2		)	(44.4		)	(42.4		)
Amortization of Loss	7.5			11.4			9.9
Amortization of Prior Service Credit	(0.1		)	(0.1		)	—
Net Pension Cost		$4.4			$7.5			$10.2


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



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2019		2018
Millions
Net Loss	$20.4		$5.8
Amortization of Prior Service Credit	0.1		0.1
Prior Service Credit Arising During the Period	—		(1.6	)
Amortization of Loss	(7.5	)	(11.4	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$13.0		$(7.1)



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2019		2018
Millions
Projected Benefit Obligation		$854.0		$747.0
Accumulated Benefit Obligation		$812.0		$713.7
Fair Value of Plan Assets		$699.6		$598.0

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



Postretirement Health and Life Obligation and Funded Status
As of December 31	2019			2018
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$176.0			$190.1
Service Cost	3.9			4.7
Interest Cost	7.3			7.1
Actuarial (Gain) Loss	10.5			(15.8		)
Benefits Paid	(14.7		)	(11.6		)
Participant Contributions	3.5			3.6
Plan Amendments (a)	(34.6		)	(2.1		)
Plan Curtailments	(2.1		)	—
Obligation, End of Year		$149.8			$176.0
Change in Plan Assets
Fair Value, Beginning of Year		$154.3			$171.0
Actual Return on Plan Assets	29.5			(9.6		)
Employer Contribution	1.1			1.0
Participant Contributions	3.5			3.6
Benefits Paid	(14.7		)	(11.7		)
Fair Value, End of Year		$173.7			$154.3
Funded Status, End of Year	$23.9			$(21.7)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$37.5			$0.4
Current Liabilities	$(0.7)			$(1.0)
Non-Current Liabilities	$(12.9)			$(21.1)


(a)	Plan design changes under the other postretirement benefit plans resulted in a decrease to the benefit obligation of $34.6 million in 2019.

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $19.1 million in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of December 31, 2019 ($18.3 million as of December 31, 2018).

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



Unrecognized Postretirement Health and Life Costs
As of December 31	2019		2018
Millions
Net Loss	$16.0		$25.0
Prior Service Credit	(36.3	)	(4.6	)
Total Unrecognized Postretirement Health and Life Cost	$(20.3)		$20.4

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



Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2019	2018
Millions
Net Loss (a)	$(16.0)	$(25.0)
Prior Service Credit	36.3	4.6
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	3.6	(1.3	)
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$23.9	$(21.7)


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



Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2019			2018			2017
Millions
Service Cost		$3.9			$4.7			$4.4
Non-Service Cost Components (a)
Interest Cost	7.3			7.1			7.7
Expected Return on Plan Assets	(10.5		)	(10.9		)	(10.5		)
Amortization of Loss	0.5			0.8			0.3
Amortization of Prior Service Credit	(2.8		)	(2.1		)	(2.0		)
Effect of Plan Curtailment	(2.1		)	—			—
Net Postretirement Health and Life Credit	$(3.7)			$(0.4)			$(0.1)


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



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2019		2018
Millions
Net (Gain) Loss	$(10.6)			$4.7
Prior Service Credit Arising During the Period	(34.6	)	(2.1		)
Amortization of Prior Service Credit	2.8		2.1
Amortization of Loss	(0.5	)	(0.8		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(42.9)		$3.9



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2020		$51.2		$8.6
2021		$50.7		$8.4
2022		$50.1		$8.2
2023		$49.8		$8.0
2024		$49.6		$8.0
Years 2025 – 2029		$239.3		$40.1

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

The pension and postretirement health and life costs recorded in regulatory long-term assets or liabilities and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2020, are as follows:



	Pension		Postretirement Health and Life
Millions
Net Loss	$12.8		$1.0
Prior Service Credit	(0.2	)	(8.0	)
Total Pension and Postretirement Health and Life Cost (Credit)	$12.6		$(7.0)



Assumptions Used to Determine Benefit Obligation
As of December 31	2019	2018
Discount Rate
Pension	3.34 - 3.47%	4.39 - 4.53%
Postretirement Health and Life	3.45%	4.47%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.10%
Health Care Trend Rates
Trend Rate	5.00 - 6.20%	5.00 - 6.46%
Ultimate Trend Rate	4.50%	4.50%
Year Ultimate Trend Rate Effective	2038	2038



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2019	2018	2017
Discount Rate	4.39 - 4.53%	3.81 - 3.96%	4.53 - 4.57%
Expected Long-Term Return on Plan Assets (a)
Pension	7.25%	7.50%	7.50%
Postretirement Health and Life	5.80 - 7.25%	6.00 - 7.50%	6.00 - 7.50%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.10%	3.70 - 4.30%


(a)	The expected long-term rates of return used to determine net periodic benefit expense for 2020 have been reduced to 6.75 percent for pension expense and 5.40 percent to 6.75 percent for postretirement health and life expense.

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

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

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2019, considered a modified PRI-2012 mortality table and mortality projection scale.



Sensitivity of a One Percent Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.8	$(1.4)
Effect on Postretirement Health and Life Obligation		$16.5	$(13.6)

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



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2019		2018		2019		2018
Equity Securities	34	%	32	%	66	%	62	%
Fixed Income Securities	62	%	60	%	33	%	34	%
Private Equity	1	%	5	%	1	%	4	%
Real Estate	3	%	3	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities as of December 31, 2019 (no shares as of December 31, 2018).

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

Following are the current targeted allocations as of December 31, 2019:



Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	32	%	60	%
Fixed Income Securities	56	%	37	%
Private Equity	6	%	—
Real Estate	6	%	3	%
	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Fair Value

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

Fair Value (Continued)

Pension Fair Value



	Fair Value as of December 31, 2019
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—			$78.5	—			$78.5
U.S. Mid-cap Growth (a)	—		35.9		—		35.9
U.S. Small-cap (a)	—		34.6		—		34.6
International	—		92.1		—		92.1
Fixed Income Securities (a)	—		425.4		—		425.4
Cash and Cash Equivalents		$7.1	—		—		7.1
Private Equity Funds	—		—			$8.0	8.0
Real Estate	—		—		18.0		18.0
Total Fair Value of Assets		$7.1		$666.5		$26.0		$699.6


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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2018		$27.8			$20.8
Actual Return on Plan Assets	0.4			(1.3		)
Purchases, Sales, and Settlements – Net	(20.2		)	(1.5		)
Balance as of December 31, 2019		$8.0			$18.0



	Fair Value as of December 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—			$59.1	—			$59.1
U.S. Mid-cap Growth (a)	—		28.1		—		28.1
U.S. Small-cap (a)	—		27.2		—		27.2
International	—		75.8		—		75.8
Fixed Income Securities (a)	—		352.9		—		352.9
Cash and Cash Equivalents		$6.3	—		—		6.3
Private Equity Funds	—		—			$27.8	27.8
Real Estate	—		—		20.8		20.8
Total Fair Value of Assets		$6.3		$543.1		$48.6		$598.0


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

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

Fair Value (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2017		$33.2			$25.5
Actual Return on Plan Assets	2.8			0.7
Purchases, Sales, and Settlements – Net	(8.2		)	(5.4		)
Balance as of December 31, 2018		$27.8			$20.8

Postretirement Health and Life Fair Value



	Fair Value as of December 31, 2019
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$33.6	—		—			$33.6
U.S. Mid-cap Growth	27.7		—		—		27.7
U.S. Small-cap	14.3		—		—		14.3
International	37.8		—		—		37.8
Fixed Income Securities:
Mutual Funds	53.4		—		—		53.4
Debt Securities	—			$4.1	—		4.1
Cash and Cash Equivalents	1.1		—		—		1.1
Private Equity Funds	—		—			$1.7	1.7
Total Fair Value of Assets		$167.9		$4.1		$1.7		$173.7


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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2018		$6.5
Actual Return on Plan Assets	0.7
Purchases, Sales, and Settlements – Net	(5.5		)
Balance as of December 31, 2019		$1.7

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

Fair Value (Continued)



	Fair Value as of December 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$29.1	—		—			$29.1
U.S. Mid-cap Growth	21.2		—		—		21.2
U.S. Small-cap	12.9		—		—		12.9
International	30.4		—		—		30.4
Fixed Income Securities:
Mutual Funds	49.6		—		—		49.6
Debt Securities	—			$4.0	—		4.0
Cash and Cash Equivalents	0.6		—		—		0.6
Private Equity Funds	—		—			$6.5	6.5
Total Fair Value of Assets		$143.8		$4.0		$6.5		$154.3


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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2017		$8.2
Actual Return on Plan Assets	0.9
Purchases, Sales, and Settlements – Net	(2.6		)
Balance as of December 31, 2018		$6.5

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

Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Employee Stock and Incentive Plans [Text Block]

EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor an ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire. The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings. ESOP employer allocations are funded with contributions paid in either cash or the issuance of ALLETE common stock at the Company’s discretion. We record compensation expense equal to the cash or current market price of stock contributed. ESOP compensation expense was $10.8 million in 2019 ($11.4 million in 2018; $11.0 million in 2017).

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock held and purchased by the ESOP were treated as unearned ESOP shares and not considered outstanding for earnings per share computations. All ESOP shares have been allocated to participants as of December 31, 2019, 2018 and 2017.

Stock-Based Compensation.

Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, restricted stock units, stock appreciation rights and other awards. There are 0.8 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.7 million of these shares remain available for issuance as of December 31, 2019.

NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

The following types of share-based awards were outstanding in 2019, 2018 or 2017:

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

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

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

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

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



Share-Based Compensation Expense
Year Ended December 31	2019		2018		2017
Millions
Performance Shares		$2.3		$2.3		$2.1
Restricted Stock Units	0.8		0.9		1.0
Total Share-Based Compensation Expense		$3.1		$3.2		$3.1
Income Tax Benefit		$0.9		$0.9		$0.9

There were no capitalized share-based compensation costs during the years ended December 31, 2019, 2018 or 2017.

As of December 31, 2019, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $2.2 million and $0.9 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.6 years.

NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

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



	2019				2018				2017
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1	129,693			$66.12	127,898			$58.23	127,580			$52.56
Granted (a)	60,747			$63.89	66,557			$76.42	50,729			$62.90
Awarded	(75,943	)	$53.44		(58,293	)		$59.82	—		—
Unearned Grant Award	—		—		—		—		(40,801	)		$46.27
Forfeited	(14,912	)		$77.14	(6,469	)		$72.99	(9,610	)		$58.29
Non-vested as of December 31	99,585			$72.78	129,693			$66.12	127,898			$58.23

(a) Shares granted include accrued dividends.

There were approximately 22,000 performance shares granted in January 2020 for the three-year performance period ending in 2022. The ultimate issuance is contingent upon the attainment of certain goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was $1.8 million. There were approximately 25,000 performance shares awarded in February 2020. The grant date fair value of the shares awarded was $1.6 million.

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



	2019				2018				2017
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1	49,771			$60.74	55,248			$56.18	54,728			$51.79
Granted (a)	13,927			$74.93	16,573			$71.11	21,241			$62.20
Awarded	(21,110	)		$52.44	(18,881	)		$55.78	(17,281	)		$49.72
Forfeited	(2,645	)		$72.43	(3,169	)		$64.92	(3,440	)		$56.00
Available as of December 31	39,943			$69.30	49,771			$60.74	55,248			$56.18

(a) Shares granted include accrued dividends.

There were approximately 14,000 restricted stock units granted in January 2020 for the vesting period ending in 2022. The grant date fair value of the restricted stock units granted was $1.1 million. There were approximately 15,000 restricted stock units awarded in February 2020. The grant date fair value of the shares awarded was $0.9 million.

Business Segments Business Segments (Notes)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

BUSINESS SEGMENTS

We present three reportable segments: Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes three operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services was our integrated water management company, which reflects operating results until the date of its sale on March 26, 2019. We also present Corporate and Other which includes two operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with our investment in Nobles 2, 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.

NOTE 14. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2019			2018		2017
Millions
Operating Revenue
Residential		$139.6			$139.7		$127.4
Commercial	145.7			147.9		139.8
Municipal	48.6			54.9		57.9
Industrial	476.4			469.5		470.5
Other Power Suppliers	153.7			170.3		161.8
CIP Financial Incentive	2.8			3.0		5.5
Other	75.6			74.2		100.9
Total Regulated Operations	1,042.4			1,059.5		1,063.8

ALLETE Clean Energy
Long-term PSA	48.0			55.2		56.9
Sale of Wind Energy Facility	—			81.1		—
Other	11.6			23.6		23.6
Total ALLETE Clean Energy	59.6			159.9		80.5

U.S. Water Services (e)
Point-in-time	19.0			100.3		95.8
Contract	9.2			38.3		36.2
Capital Project	5.2			33.5		19.8
Total U.S. Water Services	33.4			172.1		151.8

Corporate and Other
Long-term Contract	82.8			85.5		89.3
Other	22.3			21.6		33.9
Total Corporate and Other	105.1			107.1		123.2
Total Operating Revenue		$1,240.5			$1,498.6		$1,419.3
Net Income (Loss) Attributable to ALLETE (a)(b)
Regulated Operations	$154.4			$131.0		$128.4

ALLETE Clean Energy (c)	12.4			33.7		41.5
U.S. Water Services	(1.1		)	3.2		10.7

Corporate and Other (d)(e)	19.9			6.2		(8.4		)
Total Net Income Attributable to ALLETE	$185.6			$174.1		$172.2

(a) Net income in 2017 included a favorable impact of $13.0 million after-tax due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, which consisted of a $23.6 million after-tax benefit for ALLETE Clean Energy, a $9.2 million after-tax benefit for U.S. Water Services and a $19.8 million after-tax expense for Corporate and Other. The TCJA did not have an impact on net income for our Regulated Operations as the remeasurement of deferred income tax assets and liabilities primarily resulted in the recording of regulatory assets and liabilities. (See Note 1. Operations and Significant Accounting Policies and Note 4. Regulatory Matters.)


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


(c)	Net income in 2018 includes the recognition of profit for the sale of a wind energy facility to Montana-Dakota Utilities.


(d)	Net income in 2017 included 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.

(e) On March 26, 2019, ALLETE sold U.S. Water Services. The Company recognized a gain on the sale of $13.2 million after-tax which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)

NOTE 14. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2019			2018			2017
Millions
Depreciation and Amortization
Regulated Operations		$159.4			$158.0			$132.6

ALLETE Clean Energy	26.8			24.4			23.4
U.S. Water Services	2.3			10.2			9.8

Corporate and Other	13.5			13.0			11.7
Total Depreciation and Amortization		$202.0			$205.6			$177.5
Operating Expenses – Other (a)
Corporate and Other	—			$(2.0)			$(0.7)
Total Operating Expenses – Other	—			$(2.0)			$(0.7)
Interest Expense (b)
Regulated Operations		$58.9			$60.2			$57.0

ALLETE Clean Energy	2.8			3.6			4.2
U.S. Water Services	0.2			1.5			1.6

Corporate and Other	8.0			7.3			10.3

Eliminations	(5.0		)	(4.7		)	(5.3		)
Total Interest Expense		$64.9			$67.9			$67.8
Equity Earnings
Regulated Operations		$21.7			$17.5			$22.5
Income Tax Expense (Benefit) (c)
Regulated Operations (d)	$(7.1)			$(15.5)				$27.2

ALLETE Clean Energy	(11.9		)	(1.0		)	(14.2		)
U.S. Water Services	(0.4		)	1.0			(7.8		)

Corporate and Other (d)(e)	12.8			—			9.5
Total Income Tax Expense (Benefit)	$(6.6)			$(15.5)				$14.7


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


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

(c)

Income tax expense in 2017 included an income tax benefit of $13.0 million due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, which consisted of income tax benefits of $23.6 million for ALLETE Clean Energy and $9.2 million for U.S. Water Services as well as additional income tax expense of $19.8 million for Corporate and Other. 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. (See Note 1. Operations and Significant Accounting Policies and Note 4. Regulatory Matters.)

(d)

In 2017, Regulated Operations includes $14.0 million of income tax expense related to North Dakota investment tax credits transferred to Corporate and Other and higher pre-tax income for 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. There was no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax benefit of $7.9 million in 2017. (See Note 4. Regulatory Matters.)

(e) On March 26, 2019, ALLETE sold U.S. Water Services. The Company recognized income tax expense of $10.4 million for the gain on sale of U.S. Water Services which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)

NOTE 14. BUSINESS SEGMENTS (Continued)



As of December 31	2019		2018
Millions
Assets
Regulated Operations	$4,130.8		$3,952.5

ALLETE Clean Energy	1,001.5		606.6
U.S. Water Services (a)	—		295.8

Corporate and Other	350.5		310.1
Total Assets		$5,482.8		$5,165.0
Capital Expenditures
Regulated Operations	$230.9		$211.9

ALLETE Clean Energy	385.6		89.7
U.S. Water Services (a)	—		5.0

Corporate and Other	10.1		12.0
Total Capital Expenditures		$626.6		$318.6

(a) On March 26, 2019, ALLETE sold U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)

Operations and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Financial Statement Preparation [Policy Text Block]	References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with GAAP. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. Actual results could differ from those estimates.
Subsequent Events [Policy Text Block]	The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.
Principles of Consolidation [Policy Text Block]	Our Consolidated Financial Statements include the accounts of ALLETE , all of our majority‑owned subsidiary companies and variable interest entities of which ALLETE is the primary beneficiary. All material intercompany balances and transactions have been eliminated in consolidation.
Variable Interest Entities [Policy Text Block]	The accounting guidance for “Variable Interest Entities” (VIE) is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether ALLETE is the primary beneficiary of a VIE, management considers whether ALLETE has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. The accounting guidance for VIEs applies to certain ALLETE Clean Energy wind energy facilities. (See Tax Equity Financing.)
Business Segments [Policy Text Block]	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. We present three reportable segments: Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Cash and Cash Equivalents [Policy Text Block]	We consider all investments purchased with original maturities of three months or less to be cash equivalents.
Accounts Receivable [Policy Text Block]	Accounts receivable are reported on the Consolidated Balance Sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific situations and such other factors that, in our judgment, deserve recognition in estimating losses.
Long-Term Finance Receivables [Policy Text Block]	Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals.
Available-for-Sale Securities [Policy Text Block]	Available-for-sale debt and equity securities are recorded at fair value. Unrealized gains and losses on available-for-sale debt securities are included in accumulated other comprehensive income (loss), net of tax. Unrealized gains and losses on available-for-sale equity securities are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold.
Inventories [Policy Text Block]	Inventories are stated at the lower of cost or net realizable value. Inventories in our Regulated Operations segment are carried at an average cost or first-in, first-out basis. Inventories in our ALLETE Clean Energy segment and Corporate and Other businesses are carried at an average cost, first-in, first-out or specific identification basis.
Property, Plant and Equipment [Policy Text Block]	Property, plant and equipment are recorded at original cost and are reported on the Consolidated Balance Sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on property, plant and equipment for Corporate and Other operations are recognized when they are retired or otherwise disposed. When property, plant and equipment in our Regulated Operations and ALLETE Clean Energy segments are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for component depreciation except for certain circumstances where the retirement is unforeseen or unexpected. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 2. Property, Plant and Equipment.) We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.
Impairment of Long-Lived Assets [Policy Text Block]	We review our long-lived assets for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. This includes our property, plant and equipment (see Property, Plant and Equipment) and land inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value. In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our long‑lived assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future use; sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to maintain the operations.
Derivatives [Policy Text Block]	ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings.
Accounting for Stock-Based Compensation [Policy Text Block]	We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 13. Employee Stock and Incentive Plans.) Performance Shares. Under the performance share awards, the number of shares earned is contingent upon attaining specific market and performance goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies while performance goals are measured by earnings per share growth. In the case of qualified retirement, death, or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death, or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards incorporates the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients. Restricted Stock Units. Under the restricted stock unit awards, shares for participants eligible for retirement vest monthly over a three-year period. For participants not eligible for retirement, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients. Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price; we are not required to apply fair value accounting to these awards as the discount is not greater than 5 percent. RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.
Environmental Liabilities [Policy Text Block]	We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.
Leases [Policy Text Block]	We determine if a contract is, or contains, a lease at inception and recognize a right-of-use asset and lease liability for all leases with a term greater than 12 months. Our right-of-use assets and lease liabilities for operating leases are included in Other Non-Current Assets, Other Current Liabilities and Other Non-Current Liabilities, respectively, in our Consolidated Balance Sheet. We currently do not have any finance leases. Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and lease liabilities are recognized at the commencement date based on the estimated present value of lease payments over the lease term. As our leases do not provide an explicit rate, we determine the present value of future lease payments based on our estimated incremental borrowing rate using information available at the lease commencement date. The operating lease right-of-use asset includes lease payments to be made during the lease term and any lease incentives, as applicable. Our leases may include options to extend or buy out the lease at certain points throughout the term, and if it is reasonably certain that we will exercise that option at lease commencement, we include those rental payments in our calculation of the right-of-use asset and lease liability. Lease and rent expense is recognized on a straight-line basis over the lease term. Leases with a term of 12 months or less are not recognized on the Consolidated Balance Sheet. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) Leases (Continued) The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the dragline at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $3 million and is included in our calculation of the right-of-use asset and lease liability recorded. None of our other leases contain residual value guarantees.
Revenue Recognition [Policy Text Block]	Revenue is recognized upon transfer of control of promised goods or services to our customers in an amount that reflects the consideration we expect to receive in exchange for those products or services. Revenue is recognized net of allowance for returns and any taxes collected from customers, which are subsequently remitted to the appropriate governmental authorities. We account for shipping and handling activities that occur after the customer obtains control of goods as a cost rather than an additional performance obligation thereby recognizing revenue at time of shipment and accruing shipping and handling costs when control transfers to our customers. We have a right to consideration from our customers in an amount that corresponds directly with the value to the customer for our performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) Revenue (Continued) Nature of Revenue Streams Utility Residential and Commercial includes sales for electric, gas or water service to customers, who have implied contracts with the utility, under rates governed by the MPUC, PSCW or FERC. Customers are billed on a monthly cycle basis and revenue is recognized for electric, gas or water service delivered during the billing period. Revenue is accrued for service provided but not yet billed at period end. Performance obligations with these customers are satisfied at time of delivery to customer meters and simultaneously consumed. Municipal includes sales to 15 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. All wholesale electric contracts include a termination clause requiring a three-year notice to terminate. These contracts have termination dates ranging through at least 2032, with a majority of contracts effective through at least 2024. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon municipal substation or meter. Industrial includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 54 percent of total regulated utility kWh sales for the year ended December 31, 2019. Within industrial revenue, Minnesota Power has eight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. These contracts automatically renew past the contract term unless a four-year advanced written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2023 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $55 million per annum in 2020 through 2023, $20 million in 2024, and $65 million in total thereafter, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts. Other Power Suppliers includes the sale of energy under long-term PSAs with two customers as well as MISO market and liquidation sales. Expiration dates of these PSAs range from 2020 through 2028. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon delivery point defined in the contract (generally the MISO pricing node). Based on current contracts with two customers, we expect to recognize minimum revenue for fixed contract components of approximately $3 million in 2020. Other power supplier contracts that extend beyond 2020 contain variable pricing components that prevent us from estimating future minimum revenue, and therefore are not included. Other Revenue includes all remaining individually immaterial revenue streams for Minnesota Power and SWL&P, and is comprised of steam sales to paper and pulp mills, wheeling revenue and other sources. Revenue for steam sales to customers is recognized at the time steam is delivered and simultaneously consumed. Revenue is recognized at the time each performance obligation is satisfied. CIP Financial Incentive reflects certain revenue that is a result of the achievement of certain objectives for our CIP financial incentives. This revenue is accounted for in accordance with the accounting standards for alternative revenue programs which allow for the recognition of revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows for automatic adjustment of future rates, the amount of revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. CIP financial incentives are recognized in the period in which the MPUC approves the filing, which is typically mid-year. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) Revenue (Continued) Non-utility ALLETE Clean Energy Long-term PSA revenue includes all sales recognized under long-term contracts for production, curtailment, capacity and associated renewable energy credits from ALLETE Clean Energy wind energy facilities. Expiration dates of these PSAs range from 2020 through 2039. Performance obligations for these contracts are satisfied at the time energy is delivered to an agreed upon point, or production is curtailed at the request of the customer, at specified prices. Revenue from the sale of renewable energy credits is recognized at the same time the related energy is delivered to the customer when sold to the same party. Sale of Wind Energy Facility includes revenue recognized for the design, development, construction, and sale of a wind energy facility to a customer. Performance obligations for these types of agreements are satisfied at the time the completed project is transferred to the customer at the commercial operation date. Revenue from the sale of a wind energy facility is recognized at the time of asset transfer. Other is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of wind energy facility acquisitions, ALLETE Clean Energy assumed various PSAs that were above or below estimated market prices at the time of acquisition; the resulting differences between contract prices and estimated market prices are amortized to revenue over the remaining PSA term. U.S. Water Services Point-in-time revenue is recognized for purchases by customers for chemicals, consumable equipment (e.g., filters, pumps and valves) or related maintenance and repair services as the customer’s usage and needs change over time. These goods and services are purchased on an as-needed basis by customers and therefore revenue can be variable. Products are shipped to customers in accordance with the terms of each purchase order, and performance obligations are satisfied at the time of shipment of goods or when services are rendered to the customer. Contract includes monthly revenue from contracts with customers to provide chemicals, consumable equipment and services to meet customer needs during the contract period. As agreed with the customer, a fixed amount is invoiced based on the goods and services to be provided under the contract. The duration of these contracts generally range in length from three months to five years and automatically renew. A 30-day notice is required to terminate such contracts without penalty. Performance obligations are satisfied during the period as goods and service are delivered in accordance with the terms of the contract. Capital Project includes the sale of equipment and other components assembled to create a water treatment system for a customer. These projects are provided under contracts at an agreed upon price to meet a customer's specifications and typically take less than one year to complete. In general, progress payments are received throughout the project period and are recorded as contract liabilities until performance obligations are satisfied at the time the equipment and other components are delivered to the customer’s site. Corporate and Other Long-term Contract encompasses the sale and delivery of coal to customer generation facilities. Revenue is recognized on a monthly basis at the cost of production plus a specified profit per ton of coal delivered to the customer. Coal sales are secured under long-term coal supply agreements extending through 2037. Performance obligations are satisfied during the period as coal is delivered to customer generation facilities. Other primarily includes revenue from BNI Energy unrelated to coal, the sale of real estate from ALLETE Properties, and non‑rate base steam generation that is sold for use during production of paper and pulp. Performance obligations are satisfied when control transfers to the customer. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) Revenue (Continued) Payment Terms Payment terms and conditions vary across our businesses. Aside from taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered or goods provided. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customers’ energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite-producing Large Power Customers have generally predictable energy usage on a weekly basis and any differences that occur are trued-up the following month. Due to the timing difference of revenue recognition from the timing of invoicing and payment, the customer receives credit for the time value of money; however, we have determined that our contracts do not include a significant financing component as the period between when we transfer the service to the customer and when they pay for such service is minimal. Assets Recognized From the Costs to Obtain a Contract with a Customer We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less.
Revenue from Cost Recovery Riders [Policy Text Block]	reflects certain revenue that is a result of the achievement of certain objectives for our CIP financial incentives. This revenue is accounted for in accordance with the accounting standards for alternative revenue programs which allow for the recognition of revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows for automatic adjustment of future rates, the amount of revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. CIP financial incentives are recognized in the period in which the MPUC approves the filing, which is typically mid-year.
Unamortized Discount and Premium on Debt [Policy Text Block]	Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using a method which approximates the effective interest method.
Income Taxes [Policy Text Block]	We account for the collection and payment of these taxes on a net basis.ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns. We account for income taxes using the liability method in accordance with GAAP for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.
Income Taxes, Effects of Regulation [Policy Text Block]	Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property.
Unrecognized Tax Benefits [Policy Text Block]	In accordance with GAAP for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more‑likely‑than‑not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more‑likely‑than‑not” means more than 50 percent likely.We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income.The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
Excise Taxes [Policy Text Block]	We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.
New Accounting Standards [Policy Text Block]	New Accounting Pronouncements. Recently Adopted Pronouncements Disclosure Update and Simplification. In November 2018, the SEC adopted amendments to certain disclosure requirements. The amendments adopted include requirements that interim financial statements should include comparative statements for the same period in the prior financial year, except that the requirement for comparative balance sheet information may be satisfied by presenting the year-end balance sheet. It further includes a requirement analyzing the changes in each caption of shareholders’ equity either separately in a note or on the face of the financial statement. These amendments were effective for ALLETE in the first quarter of 2019. We have included the presentation of our Statement of Shareholders’ Equity to meet these requirements. Leases. In 2016, the FASB issued an accounting standard update which revised the existing guidance for leases. Under the revised guidance, lessees are required to recognize right-of-use assets and lease liabilities on the Consolidated Balance Sheet for leases with terms greater than 12 months. The new standard also requires additional qualitative and quantitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement and presentation of expenses and cash flows from leases is not expected to significantly change as a result of the new guidance. The Company adopted this guidance in the first quarter of 2019 using the optional transition method and the package of practical expedients, which allowed for the adoption of the standard as of January 1, 2019, without restating previously disclosed information. Management elected the optional transition method of adoption due to the overall immateriality of the balance sheet gross up in the period of adoption. The package of practical expedients allowed management to not reassess the lease classification for leases, including those that had expired during the periods presented or that still existed at the time of adoption. We have included additional disclosures in the notes to the consolidated financial statements.
Asset Retirement Obligations [Policy Text Block]	We recognize, at fair value, obligations associated with the retirement of certain tangible, long‑lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (AROs) relate primarily to the decommissioning of our coal-fired and wind energy facilities, and land reclamation at BNI Energy. AROs are included in Other Non-Current Liabilities on the Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives. Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, the period of remediation is indeterminable and removal liabilities have not been recognized. Long-standing ratemaking practices approved by applicable state and federal regulatory authorities have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-AROs. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with GAAP for AROs.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.
Equity Method Investments [Policy Text Block]	We account for our investment in Nobles 2 under the equity method of accounting.We account for our investment in ATC under the equity method of accounting.The Company assesses our equity investments in ATC and Nobles 2 for impairment whenever events or changes in circumstances indicate that the carrying amount of our investments may not be recoverable.
Fair Value Measurement [Policy Text Block]	Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy.Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). (See Note 7. Fair Value)
Fair Value Transfers [Policy Text Block]	The Company’s policy is to recognize transfers in and transfers out of Levels as of the actual date of the event or change in circumstances that caused the transfer.
Property, Plant and Equipment Impairment [Policy Text Block]	The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable.
Pension and Other Postretirement Benefit Plans [Policy Text Block]	According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. Accounting for defined benefit pension and other postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset (regulatory liability) on the Consolidated Balance Sheet, in accordance with the accounting standards for the effect of certain types of regulation applicable to our Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other operations are recognized in accumulated other comprehensive income. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return. The discount rate is computed using a bond matching study which utilizes a portfolio of high quality bonds that produce cash flows similar to the projected costs of our pension and other postretirement plans. The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations.Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the pension plans. Contributions are based on estimates and assumptions which are subject to change.
Employee Stock Ownership Plan [Policy Text Block]	The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings. ESOP employer allocations are funded with contributions paid in either cash or the issuance of ALLETE common stock at the Company’s discretion. According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock held and purchased by the ESOP were treated as unearned ESOP shares and not considered outstanding for earnings per share computations. All ESOP shares have been allocated to participants as of December 31, 2019, 2018 and 2017.
Short-term Leases [Policy Text Block]	Lease and rent expense is recognized on a straight-line basis over the lease term. Leases with a term of 12 months or less are not recognized on the Consolidated Balance Sheet.

Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Cash, Cash Equivalents and Restricted Cash [Table Text Block]



Cash, Cash Equivalents and Restricted Cash	December 31, 2019		December 31, 2018		December 31, 2017
Millions
Cash and Cash Equivalents		$69.3		$69.1		$98.9
Restricted Cash included in Prepayments and Other	2.8		1.3		2.6
Restricted Cash included in Other Non-Current Assets	20.4		8.6		8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		$92.5		$79.0		$110.1

Supplemental Statement of Cash Flow Information [Table Text Block]

Supplemental Statement of Cash Flow Information.



Consolidated Statement of Cash Flows
Year Ended December 31	2019		2018		2017
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$63.5		$66.0		$64.5
Recognition of Right-of-use Assets and Lease Liabilities (a)		$28.7	—		—
Remeasurement of Deferred Income Taxes Resulting from the TCJA
Increase in Regulatory Assets	—		—			$80.9
Decrease in Investment in ATC	—		—		$(27.9)
Decrease in Deferred Income Taxes	—		—		$(353.6)
Increase in Regulatory Liabilities	—		—			$393.6
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$33.9		$(0.1)		$67.2
Reclassification of Property, Plant and Equipment to Inventory (b)	—			$46.3	—
Capitalized Asset Retirement Costs	$20.7		$14.2		$(15.6)
AFUDC–Equity		$2.3		$1.2		$1.2
ALLETE Common Stock Contributed to Pension Plans	—		—			$13.5


(a)	See Leases.

(b)

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2019		2018
Millions
Trade Accounts Receivable (a)
Billed		$77.2		$121.7
Unbilled	20.1		24.4
Less: Allowance for Doubtful Accounts	0.9		1.7
Total Accounts Receivable		$96.4		$144.4

(a)

On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related accounts receivable from the Consolidated Balance Sheet.

Inventories – Net [Table Text Block]



Inventories – Net
As of December 31	2019		2018
Millions
Fuel (a)		$25.9		$26.0
Materials and Supplies	46.9		44.2
Raw Materials (b)	—		2.8
Work in Progress (b)	—		6.1
Finished Goods (b)	—		8.4
Reserve for Obsolescence (b)	—		(0.8		)
Total Inventories – Net		$72.8		$86.7


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

(b) On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related inventory items from the Consolidated Balance Sheet.

Other Non-Current Assets [Table Text Block]



Other Non-Current Assets
As of December 31	2019		2018
Millions
Contract Assets (a)		$28.0		$30.7
Finance Receivable (b)	—		10.4
Operating Lease Right-of-use Assets (c)	28.6		—
ALLETE Properties	21.9		24.4
Restricted Cash	20.4		8.6
Other Postretirement Benefit Plans	37.5		0.4
Other	80.8		77.9
Total Other Non-Current Assets		$217.2		$152.4


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


(b)	Finance Receivable related to the 2016 sale of Ormond Crossings and Lake Swamp, which was collected in the second quarter of 2019.

(c)

See Leases.

Other Current Liabilities [Table Text Block]



Other Current Liabilities
As of December 31	2019		2018
Millions
Provision for Interim Rate Refund (a)	—			$40.0
PSAs		$12.3	12.6
Contract Liabilities (b)	—		7.6
Provision for Tax Reform Refund (c)	0.2		10.7
Contingent Consideration (d)	—		3.8
Operating Lease Liabilities (e)	6.9		—
Other	41.0		53.8
Total Other Current Liabilities		$60.4		$128.5

(a) Provision for Interim Rate Refund was refunded to Minnesota Power’s retail customers in the second quarter of 2019.


(b)	Contract Liabilities consist of deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.


(c)	Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020.


(d)	Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019.

(e)

See Leases.

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities
As of December 31	2019		2018
Millions
Asset Retirement Obligation		$160.3		$138.6
PSAs	64.6		76.9
Operating Lease Liabilities (a)	21.8		—
Other	46.3		47.1
Total Other Non-Current Liabilities		$293.0		$262.6


(a)	See Leases.

Lease, Cost [Table Text Block]

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



	December 31, 2019
Millions
Operating Lease Cost		$9.4

Other Information:
Operating Cash Flows From Operating Leases		$9.4

Additional information related to leases was as follows:



	December 31, 2019
Millions
Balance Sheet Information Related to Leases:
Other Non-Current Assets		$28.6
Total Operating Lease Right-of-use Assets		$28.6

Other Current Liabilities		$6.9
Other Non-Current Liabilities	21.8
Total Operating Lease Liabilities		$28.7

Weighted Average Remaining Lease Term (Years):
Operating Leases - Vehicles and Equipment	4
Operating Leases - Land and Other	28

Weighted Average Discount Rate:
Operating Leases - Vehicles and Equipment	3.7		%
Operating Leases - Land and Other	4.1		%

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

Maturities of lease liabilities were as follows:



	December 31, 2019
Millions
2020		$6.6
2021	6.0
2022	5.0
2023	3.2
2024	2.9
Thereafter	11.5
Total Lease Payments Due	35.2
Less: Imputed Interest	6.5
Total Lease Obligations	28.7
Less: Current Lease Obligations	6.9
Total Long-term Lease Obligations		$21.8

Operating Expenses – Other [Table Text Block]



Operating Expenses – Other
Year Ended December 31	2019	2018	2017
Millions
Change in Fair Value of Contingent Consideration (a)	—	$(2.0)	$(0.7)
Total Operating Expenses – Other	—	$(2.0)	$(0.7)

(a)

Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019. (See Note 7. Fair Value.)

Other Income (Expense) - Other [Table Text Block]



Other Income (Expense) - Other
Year Ended December 31	2019		2018		2017
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credit (a)		$7.7		$4.6		$3.9
Interest and Investment Earnings	4.4		0.5		1.8
AFUDC - Equity	2.3		1.2		1.2
Gain (Loss) on Land Sales	2.1		0.9		(0.5		)
Other	2.2		0.6		(0.1		)
Total Other Income (Expense) - Other		$18.7		$7.8		$6.3

(a)

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

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment and Estimated Useful Lives of Property, Plant and Equipment [Table Text Block]



Estimated Useful Lives of Property, Plant and Equipment (Years)
Regulated Operations
Generation	4 to 50	ALLETE Clean Energy	5 to 35
Transmission	52 to 71	Corporate and Other	3 to 50
Distribution	19 to 68



Property, Plant and Equipment
As of December 31	2019			2018
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,555.8			$4,490.6
Construction Work in Progress	383.6			251.1
Accumulated Depreciation	(1,635.3		)	(1,549.6		)
Regulated Operations – Net	3,304.1			3,192.1
ALLETE Clean Energy
Property, Plant and Equipment in Service	686.0			488.4
Construction Work in Progress	351.3			164.5
Accumulated Depreciation	(86.8		)	(73.0		)
ALLETE Clean Energy – Net	950.5			579.9
U.S. Water Services (a)
Property, Plant and Equipment in Service	—			30.1
Accumulated Depreciation	—			(14.0		)
U.S. Water Services – Net	—			16.1
Corporate and Other (b)
Property, Plant and Equipment in Service	231.9			214.3
Construction Work in Progress	3.8			6.6
Accumulated Depreciation	(113.3		)	(104.6		)
Corporate and Other – Net	122.4			116.3
Property, Plant and Equipment – Net		$4,377.0			$3,904.4


(a)	On March 26, 2019, ALLETE completed the sale of U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)


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

Asset Retirement Obligations [Table Text Block]



Asset Retirement Obligations
Millions
Obligation as of December 31, 2017		$122.7
Accretion	7.0
Liabilities Settled	(5.3		)
Revisions in Estimated Cash Flows	14.2
Obligation as of December 31, 2018	138.6
Accretion	7.2
Liabilities Recognized	1.4
Liabilities Settled	(4.6		)
Revisions in Estimated Cash Flows	17.7
Obligation as of December 31, 2019		$160.3

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]

NOTE 4. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2019		2018
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (a)		$212.9		$218.5
Income Taxes (b)	123.4		105.5
Asset Retirement Obligations (c)	32.0		32.6
Cost Recovery Riders (d)	24.7		—
Boswell 1 & 2 Net Plant and Equipment (e)	10.7		16.3
Manufactured Gas Plant (f)	8.2		8.0
PPACA Income Tax Deferral	4.8		5.0
Other	3.8		3.6
Total Non-Current Regulatory Assets		$420.5		$389.5
Current Regulatory Liabilities (g)
Provision for Interim Rate Refund (h)	—			$40.0
Provision for Tax Reform Refund (i)		$0.2	10.7
Transmission Formula Rates	1.7		4.4
Total Current Regulatory Liabilities	1.9		55.1
Non-Current Regulatory Liabilities
Income Taxes (b)	407.2		396.4
Wholesale and Retail Contra AFUDC (j)	79.3		64.4
Plant Removal Obligations (k)	35.5		25.1
Defined Benefit Pension and Other Postretirement Benefit Plans (a)	17.0		—
North Dakota Investment Tax Credits (l)	12.3		14.7
Conservation Improvement Program (m)	5.4		1.5
Cost Recovery Riders (d)	—		6.9
Transmission Formula Rates	—		1.6
Other	3.6		1.5
Total Non-Current Regulatory Liabilities	560.3		512.1
Total Regulatory Liabilities		$562.2		$567.2

(a)


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


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

(d)


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


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


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


(h)	This amount was refunded to Minnesota Power’s regulated retail customers in the second quarter of 2019.


(i)	Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020.


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


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


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

(m)

Fair Value (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2019
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$11.1	—		—		$11.1
Available-for-sale – Corporate and Governmental Debt Securities (b)	—			$9.7	—	9.7
Cash Equivalents	0.9		—		—	0.9
Total Fair Value of Assets		$12.0		$9.7	—		$21.7

Liabilities:
Deferred Compensation (c)	—			$21.2	—		$21.2
Total Fair Value of Liabilities	—			$21.2	—		$21.2
Total Net Fair Value of Assets (Liabilities)		$12.0	$(11.5)		—	$0.5


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


(b)	As of December 31, 2019, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $2.1 million, in one year to less than three years was $7.2 million, in three years to less than five years was zero and in five or more years was $0.4 million.

(c)

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



	Fair Value as of December 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$12.2	—		—			$12.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.0	—		8.0
Cash Equivalents	1.0		—		—		1.0
Total Fair Value of Assets		$13.2		$8.0	—			$21.2

Liabilities: (b)
Deferred Compensation	—			$19.8	—			$19.8
U.S. Water Services Contingent Consideration	—		—			$3.8	3.8
Total Fair Value of Liabilities	—			$19.8		$3.8		$23.6
Total Net Fair Value of Assets (Liabilities)		$13.2	$(11.8)		$(3.8)		$(2.4)


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

(b)

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

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
December 31, 2019	$1,622.6	$1,791.8
December 31, 2018	$1,495.2	$1,534.6

Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

First Mortgage Bonds Issued March 1, 2019 [Table Text Block]

On March 1, 2019, ALLETE issued and sold the following First Mortgage Bonds (the Bonds):



Maturity Date	Principal Amount	Interest Rate
March 1, 2029	$70 Million	4.08%
March 1, 2049	$30 Million	4.47%

Long-term Debt [Table Text Block]



Long-Term Debt
As of December 31	2019			2018
Millions
First Mortgage Bonds
8.17% Series Due 2019	—				$42.0
5.28% Series Due 2020		$35.0		35.0
2.80% Series Due 2020	40.0			40.0
4.85% Series Due 2021	15.0			15.0
3.02% Series Due 2021	60.0			60.0
3.40% Series Due 2022	75.0			75.0
6.02% Series Due 2023	75.0			75.0
3.69% Series Due 2024	60.0			60.0
4.90% Series Due 2025	30.0			30.0
5.10% Series Due 2025	30.0			30.0
3.20% Series Due 2026	75.0			75.0
5.99% Series Due 2027	60.0			60.0
3.30% Series Due 2028	40.0			40.0
4.08% Series Due 2029	70.0			—
3.74% Series Due 2029	50.0			50.0
3.86% Series Due 2030	60.0			60.0
5.69% Series Due 2036	50.0			50.0
6.00% Series Due 2040	35.0			35.0
5.82% Series Due 2040	45.0			45.0
4.08% Series Due 2042	85.0			85.0
4.21% Series Due 2043	60.0			60.0
4.95% Series Due 2044	40.0			40.0
5.05% Series Due 2044	40.0			40.0
4.39% Series Due 2044	50.0			50.0
4.07% Series Due 2048	60.0			60.0
4.47% Series Due 2049	30.0			—
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Unsecured Term Loan Variable Rate Due 2020	110.0			10.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024	47.8			57.2
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8			27.8
Senior Unsecured Notes 3.11% Due 2027	80.0			80.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0			15.0
SWL&P First Mortgage Bonds 4.14% Series Due 2048	12.0			12.0
Other Long-Term Debt, 3.11% – 5.75% Due 2020 – 2037	46.5			67.7
Unamortized Debt Issuance Costs	(8.8		)	(9.2		)
Total Long-Term Debt	1,613.8			1,486.0
Less: Due Within One Year	212.9			57.5
Net Long-Term Debt		$1,400.9			$1,428.5

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
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Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
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-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

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+ Details

Commitments, Guarantees and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Annual Payments for Certain Long-Term Commitments [Table Text Block]

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



As of December 31, 2019
Millions	2020		2021		2022		2023		2024		Thereafter
Capital Purchase Obligations		$292.7	—		—		—		—		—
Easements (a)		$5.0		$5.3		$5.4		$5.5		$5.5		$170.4
PPAs (b)		$113.0		$122.5		$145.5		$145.6		$138.5		$1,386.7
Other Purchase Obligations (c)		$22.8		$9.6	—		—		—			$0.1


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


(b)	Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with Nobles 2 commencing in 2020 as it is subject to construction of a wind energy facility. (See Power Purchase Agreements.)

(c)

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

Minnesota Power has also entered into the following PSAs for the sale of capacity and energy as of December 31, 2019:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(a)
PSA 2	(b)	Capacity	June 2022	May 2025	Fixed
PSA 3	100 MW	Capacity	June 2025	May 2028	Fixed
Minnkota Power	(c)	Capacity / Energy	June 2014	December 2026	(c)
Oconto Electric Cooperative	25 MW	Capacity / Energy	January 2019	May 2026	Fixed
Silver Bay Power	(d)	Energy	January 2017	December 2031	(e)


(a)	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.


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

(c)

(d)

(e)

The energy pricing was fixed through 2019 with pricing in later years escalating at a fixed rate annually and adjusted for changes in a natural gas index.

Minnesota Power has also entered into the following PPAs for the purchase of capacity and energy as of December 31, 2019:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Calpine Corporation	25 MW	Capacity	June 2019	May 2026	Fixed
Great River Energy
PPA 1	50 MW	Capacity / Energy	June 2016	May 2020	(a)
PPA 2	50 MW	Capacity	June 2016	May 2020	Fixed
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
Manitoba Hydro
PPA 1	(b)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	50 MW	Capacity / Energy	June 2015	May 2020	(c)
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
PPA 4 (d)	250 MW	Capacity / Energy	June 2020	May 2035	(e)
PPA 5 (d)	133 MW	Energy	(f)	(f)	Forward Market Prices
Minnkota Power	50 MW	Capacity / Energy	June 2016	May 2020	(g)
Nobles 2 (h)	(h)	Capacity / Energy	(h)	(h)	Fixed
Oliver Wind I	(i)	Energy	December 2006	December 2040	Fixed
Oliver Wind II	(i)	Energy	December 2007	December 2040	Fixed


(a)	The capacity price is fixed and the energy price is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index, as well as market prices.


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


(c)	The capacity and energy prices are adjusted annually by the change in a governmental inflationary index.


(d)	Agreements are subject to the construction of the GNTL and MMTP. (See Great Northern Transmission Line.)


(e)	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 component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.


(f)	The contract term will be the 20-year period beginning on the in-service date for the GNTL. (See Great Northern Transmission Line.)


(g)	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.


(h)	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota for 20 years beginning upon commercial operation of the wind energy facility which is currently expected in fourth quarter of 2020. (See Note 4. Regulatory Matters and Note 5. Equity Investments.)


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

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2019			2018			2017
Millions
Current Income Tax Expense (a)
Federal	—			—			—
State	$0.1			$0.3			$0.3
Total Current Income Tax Expense		$0.1			$0.3			$0.3
Deferred Income Tax Expense (Benefit)
Federal (b)	$(27.8)			$(26.2)				$12.1
Federal – Remeasurement of Deferred Income Taxes (c)	—			—			(13.0		)
State	21.7			11.0			15.8
Investment Tax Credit Amortization	(0.6		)	(0.6		)	(0.5		)
Total Deferred Income Tax Expense (Benefit)	$(6.7)			$(15.8)				$14.4
Total Income Tax Expense (Benefit)	$(6.6)			$(15.5)				$14.7

(a)


(b)	For the years ended December 31, 2019, and 2018, the federal tax benefit is primarily due to production tax credits, and the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA.

(c)

For the year ended December 31, 2017, the federal deferred income tax benefit is due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Table Text Block]



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2019			2018			2017
Millions
Income Before Non-Controlling Interest and Income Taxes		$178.9			$158.6			$186.9
Statutory Federal Income Tax Rate	21		%	21		%	35		%
Income Taxes Computed at Statutory Federal Rate		$37.6			$33.3			$65.4
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	17.2			8.9			10.5
Production Tax Credits	(50.7		)	(45.0		)	(45.1		)
Regulatory Differences – Excess Deferred Tax Benefit (a)	(8.8		)	(8.2		)	1.2
U.S. Water Services Sale of Stock Basis Difference	1.7			—			—
Change in Fair Value of Contingent Consideration	—			(0.4		)	—
Remeasurement of Deferred Income Taxes (b)	—			—			(13.0		)
Other	(3.6		)	(4.1		)	(4.3		)
Total Income Tax Expense (Benefit)		($6.6	)		($15.5	)		$14.7


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

(b)

Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Deferred Tax Assets and Liabilities [Table Text Block]



Deferred Income Tax Assets and Liabilities
As of December 31	2019			2018
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation		$49.9			$62.2
Property-Related	76.9			95.2
NOL Carryforwards	63.2			86.1
Tax Credit Carryforwards	395.5			349.8
Power Sales Agreements	23.7			27.5
Regulatory Liabilities	116.9			113.4
Other	23.4			25.1
Gross Deferred Income Tax Assets	749.5			759.3
Deferred Income Tax Asset Valuation Allowance	(70.0		)	(66.5		)
Total Deferred Income Tax Assets		$679.5			$692.8
Deferred Income Tax Liabilities
Property-Related		$713.4			$752.5
Regulatory Asset for Benefit Obligations	54.5			61.0
Unamortized Investment Tax Credits	31.6			32.2
Partnership Basis Differences	49.4			40.8
Regulatory Assets	35.4			29.9
Other	8.0			—
Total Deferred Income Tax Liabilities		$892.3			$916.4
Net Deferred Income Taxes (a)		$212.8			$223.6

(a)

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

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
As of December 31	2019	2018
Millions
Federal NOL Carryforwards (a)	$211.3		$319.0
Federal Tax Credit Carryforwards	$302.5	$256.4
State NOL Carryforwards (a)	$274.8	$305.8
State Tax Credit Carryforwards (b)	$23.4	$27.4


(a)	Pre-tax amounts.

(b)

Net of a $69.6 million valuation allowance as of December 31, 2019 ($66.0 million as of December 31, 2018).

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2019			2018			2017
Millions
Balance at January 1		$1.6			$1.7			$2.0
Additions for Tax Positions Related to the Current Year	0.1			0.1			0.1
Additions for Tax Positions Related to Prior Years	0.1			0.1			0.1
Reductions for Tax Positions Related to Prior Years	(0.4		)	(0.2		)	(0.1		)
Lapse of Statute	—			(0.1		)	(0.4		)
Balance as of December 31		$1.4			$1.6			$1.7

Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2019

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2020		$51.2		$8.6
2021		$50.7		$8.4
2022		$50.1		$8.2
2023		$49.8		$8.0
2024		$49.6		$8.0
Years 2025 – 2029		$239.3		$40.1

Defined Benefit Costs Recorded in Regulatory Long-Term Assets or Liabilities and Accumulated Other Comprehensive Income Expected to be Recognized over Next Fiscal Year [Table Text Block]



	Pension		Postretirement Health and Life
Millions
Net Loss	$12.8		$1.0
Prior Service Credit	(0.2	)	(8.0	)
Total Pension and Postretirement Health and Life Cost (Credit)	$12.6		$(7.0)

Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs [Table Text Block]



Assumptions Used to Determine Benefit Obligation
As of December 31	2019	2018
Discount Rate
Pension	3.34 - 3.47%	4.39 - 4.53%
Postretirement Health and Life	3.45%	4.47%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.10%
Health Care Trend Rates
Trend Rate	5.00 - 6.20%	5.00 - 6.46%
Ultimate Trend Rate	4.50%	4.50%
Year Ultimate Trend Rate Effective	2038	2038



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2019	2018	2017
Discount Rate	4.39 - 4.53%	3.81 - 3.96%	4.53 - 4.57%
Expected Long-Term Return on Plan Assets (a)
Pension	7.25%	7.50%	7.50%
Postretirement Health and Life	5.80 - 7.25%	6.00 - 7.50%	6.00 - 7.50%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.10%	3.70 - 4.30%


(a)	The expected long-term rates of return used to determine net periodic benefit expense for 2020 have been reduced to 6.75 percent for pension expense and 5.40 percent to 6.75 percent for postretirement health and life expense.

Plan Asset Actual and Target Allocations [Table Text Block]

Following are the current targeted allocations as of December 31, 2019:



Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	32	%	60	%
Fixed Income Securities	56	%	37	%
Private Equity	6	%	—
Real Estate	6	%	3	%
	100	%	100	%

(a)

Includes VEBAs and irrevocable grantor trusts.



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2019		2018		2019		2018
Equity Securities	34	%	32	%	66	%	62	%
Fixed Income Securities	62	%	60	%	33	%	34	%
Private Equity	1	%	5	%	1	%	4	%
Real Estate	3	%	3	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Pension Obligation and Funded Status
As of December 31	2019			2018
Millions
Accumulated Benefit Obligation		$812.0			$713.7
Change in Benefit Obligation
Obligation, Beginning of Year		$747.0			$793.2
Service Cost	9.3			11.0
Interest Cost	31.9			29.6
Plan Amendments	—			(1.5		)
Plan Curtailments	—			(6.9		)
Actuarial (Gain) Loss	98.3			(53.0		)
Benefits Paid	(53.4		)	(49.5		)
Participant Contributions	20.9			24.1
Obligation, End of Year		$854.0			$747.0
Change in Plan Assets
Fair Value, Beginning of Year		$598.0			$628.2
Actual Return on Plan Assets	122.1			(21.2		)
Employer Contribution (a)	32.9			40.5
Benefits Paid	(53.4		)	(49.5		)
Fair Value, End of Year		$699.6			$598.0
Funded Status, End of Year	$(154.4)			$(149.0)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.6)			$(1.6)
Non-Current Liabilities	$(152.8)			$(147.4)


(a)	Includes Participant Contributions noted above.

Amounts Recognized in Consolidated Balance Sheet [Table Text Block]



Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2019	2018
Millions
Net Loss	$(243.4)	$(230.5)
Prior Service Credit	1.3	1.4
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	87.7	80.1
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(154.4)	$(149.0)

Components of Net Periodic Cost [Table Text Block]



Components of Net Periodic Pension Cost
Year Ended December 31	2019			2018			2017
Millions
Service Cost		$9.3			$11.0			$10.2
Non-Service Cost Components (a)
Interest Cost	31.9			29.6			32.5
Expected Return on Plan Assets	(44.2		)	(44.4		)	(42.4		)
Amortization of Loss	7.5			11.4			9.9
Amortization of Prior Service Credit	(0.1		)	(0.1		)	—
Net Pension Cost		$4.4			$7.5			$10.2

(a)

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

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets [Table Text Block]



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2019		2018
Millions
Projected Benefit Obligation		$854.0		$747.0
Accumulated Benefit Obligation		$812.0		$713.7
Fair Value of Plan Assets		$699.6		$598.0

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities [Table Text Block]



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2019		2018
Millions
Net Loss	$20.4		$5.8
Amortization of Prior Service Credit	0.1		0.1
Prior Service Credit Arising During the Period	—		(1.6	)
Amortization of Loss	(7.5	)	(11.4	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$13.0		$(7.1)

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2019
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—			$78.5	—			$78.5
U.S. Mid-cap Growth (a)	—		35.9		—		35.9
U.S. Small-cap (a)	—		34.6		—		34.6
International	—		92.1		—		92.1
Fixed Income Securities (a)	—		425.4		—		425.4
Cash and Cash Equivalents		$7.1	—		—		7.1
Private Equity Funds	—		—			$8.0	8.0
Real Estate	—		—		18.0		18.0
Total Fair Value of Assets		$7.1		$666.5		$26.0		$699.6

(a)

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



	Fair Value as of December 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—			$59.1	—			$59.1
U.S. Mid-cap Growth (a)	—		28.1		—		28.1
U.S. Small-cap (a)	—		27.2		—		27.2
International	—		75.8		—		75.8
Fixed Income Securities (a)	—		352.9		—		352.9
Cash and Cash Equivalents		$6.3	—		—		6.3
Private Equity Funds	—		—			$27.8	27.8
Real Estate	—		—		20.8		20.8
Total Fair Value of Assets		$6.3		$543.1		$48.6		$598.0


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

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2017		$33.2			$25.5
Actual Return on Plan Assets	2.8			0.7
Purchases, Sales, and Settlements – Net	(8.2		)	(5.4		)
Balance as of December 31, 2018		$27.8			$20.8



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2018		$27.8			$20.8
Actual Return on Plan Assets	0.4			(1.3		)
Purchases, Sales, and Settlements – Net	(20.2		)	(1.5		)
Balance as of December 31, 2019		$8.0			$18.0

Postretirement Health and Life [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Postretirement Health and Life Obligation and Funded Status
As of December 31	2019			2018
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$176.0			$190.1
Service Cost	3.9			4.7
Interest Cost	7.3			7.1
Actuarial (Gain) Loss	10.5			(15.8		)
Benefits Paid	(14.7		)	(11.6		)
Participant Contributions	3.5			3.6
Plan Amendments (a)	(34.6		)	(2.1		)
Plan Curtailments	(2.1		)	—
Obligation, End of Year		$149.8			$176.0
Change in Plan Assets
Fair Value, Beginning of Year		$154.3			$171.0
Actual Return on Plan Assets	29.5			(9.6		)
Employer Contribution	1.1			1.0
Participant Contributions	3.5			3.6
Benefits Paid	(14.7		)	(11.7		)
Fair Value, End of Year		$173.7			$154.3
Funded Status, End of Year	$23.9			$(21.7)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$37.5			$0.4
Current Liabilities	$(0.7)			$(1.0)
Non-Current Liabilities	$(12.9)			$(21.1)

(a)

Plan design changes under the other postretirement benefit plans resulted in a decrease to the benefit obligation of $34.6 million in 2019.

Amounts Recognized in Consolidated Balance Sheet [Table Text Block]



Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2019	2018
Millions
Net Loss (a)	$(16.0)	$(25.0)
Prior Service Credit	36.3	4.6
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	3.6	(1.3	)
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$23.9	$(21.7)

(a)

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

Components of Net Periodic Cost [Table Text Block]



Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2019			2018			2017
Millions
Service Cost		$3.9			$4.7			$4.4
Non-Service Cost Components (a)
Interest Cost	7.3			7.1			7.7
Expected Return on Plan Assets	(10.5		)	(10.9		)	(10.5		)
Amortization of Loss	0.5			0.8			0.3
Amortization of Prior Service Credit	(2.8		)	(2.1		)	(2.0		)
Effect of Plan Curtailment	(2.1		)	—			—
Net Postretirement Health and Life Credit	$(3.7)			$(0.4)			$(0.1)

(a)

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

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities [Table Text Block]



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2019		2018
Millions
Net (Gain) Loss	$(10.6)			$4.7
Prior Service Credit Arising During the Period	(34.6	)	(2.1		)
Amortization of Prior Service Credit	2.8		2.1
Amortization of Loss	(0.5	)	(0.8		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(42.9)		$3.9

Unrecognized Postretirement Health and Life Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
As of December 31	2019		2018
Millions
Net Loss	$16.0		$25.0
Prior Service Credit	(36.3	)	(4.6	)
Total Unrecognized Postretirement Health and Life Cost	$(20.3)		$20.4

Sensitivity of a One Percent Change in Health Care Trend Rates [Table Text Block]



Sensitivity of a One Percent Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.8	$(1.4)
Effect on Postretirement Health and Life Obligation		$16.5	$(13.6)

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$29.1	—		—			$29.1
U.S. Mid-cap Growth	21.2		—		—		21.2
U.S. Small-cap	12.9		—		—		12.9
International	30.4		—		—		30.4
Fixed Income Securities:
Mutual Funds	49.6		—		—		49.6
Debt Securities	—			$4.0	—		4.0
Cash and Cash Equivalents	0.6		—		—		0.6
Private Equity Funds	—		—			$6.5	6.5
Total Fair Value of Assets		$143.8		$4.0		$6.5		$154.3

(a)

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



	Fair Value as of December 31, 2019
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$33.6	—		—			$33.6
U.S. Mid-cap Growth	27.7		—		—		27.7
U.S. Small-cap	14.3		—		—		14.3
International	37.8		—		—		37.8
Fixed Income Securities:
Mutual Funds	53.4		—		—		53.4
Debt Securities	—			$4.1	—		4.1
Cash and Cash Equivalents	1.1		—		—		1.1
Private Equity Funds	—		—			$1.7	1.7
Total Fair Value of Assets		$167.9		$4.1		$1.7		$173.7

(a)

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

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2018		$6.5
Actual Return on Plan Assets	0.7
Purchases, Sales, and Settlements – Net	(5.5		)
Balance as of December 31, 2019		$1.7



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2017		$8.2
Actual Return on Plan Assets	0.9
Purchases, Sales, and Settlements – Net	(2.6		)
Balance as of December 31, 2018		$6.5

Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Share-Based Compensation Expense [Table Text Block]

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



Share-Based Compensation Expense
Year Ended December 31	2019		2018		2017
Millions
Performance Shares		$2.3		$2.3		$2.1
Restricted Stock Units	0.8		0.9		1.0
Total Share-Based Compensation Expense		$3.1		$3.2		$3.1
Income Tax Benefit		$0.9		$0.9		$0.9

Performance Shares [Table Text Block]

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



	2019				2018				2017
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1	129,693			$66.12	127,898			$58.23	127,580			$52.56
Granted (a)	60,747			$63.89	66,557			$76.42	50,729			$62.90
Awarded	(75,943	)	$53.44		(58,293	)		$59.82	—		—
Unearned Grant Award	—		—		—		—		(40,801	)		$46.27
Forfeited	(14,912	)		$77.14	(6,469	)		$72.99	(9,610	)		$58.29
Non-vested as of December 31	99,585			$72.78	129,693			$66.12	127,898			$58.23

(a) Shares granted include accrued dividends.

Restricted Stock Units [Table Text Block]

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



	2019				2018				2017
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1	49,771			$60.74	55,248			$56.18	54,728			$51.79
Granted (a)	13,927			$74.93	16,573			$71.11	21,241			$62.20
Awarded	(21,110	)		$52.44	(18,881	)		$55.78	(17,281	)		$49.72
Forfeited	(2,645	)		$72.43	(3,169	)		$64.92	(3,440	)		$56.00
Available as of December 31	39,943			$69.30	49,771			$60.74	55,248			$56.18

(a) Shares granted include accrued dividends.

Business Segments Business Segment (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]



Year Ended December 31	2019			2018		2017
Millions
Operating Revenue
Residential		$139.6			$139.7		$127.4
Commercial	145.7			147.9		139.8
Municipal	48.6			54.9		57.9
Industrial	476.4			469.5		470.5
Other Power Suppliers	153.7			170.3		161.8
CIP Financial Incentive	2.8			3.0		5.5
Other	75.6			74.2		100.9
Total Regulated Operations	1,042.4			1,059.5		1,063.8

ALLETE Clean Energy
Long-term PSA	48.0			55.2		56.9
Sale of Wind Energy Facility	—			81.1		—
Other	11.6			23.6		23.6
Total ALLETE Clean Energy	59.6			159.9		80.5

U.S. Water Services (e)
Point-in-time	19.0			100.3		95.8
Contract	9.2			38.3		36.2
Capital Project	5.2			33.5		19.8
Total U.S. Water Services	33.4			172.1		151.8

Corporate and Other
Long-term Contract	82.8			85.5		89.3
Other	22.3			21.6		33.9
Total Corporate and Other	105.1			107.1		123.2
Total Operating Revenue		$1,240.5			$1,498.6		$1,419.3
Net Income (Loss) Attributable to ALLETE (a)(b)
Regulated Operations	$154.4			$131.0		$128.4

ALLETE Clean Energy (c)	12.4			33.7		41.5
U.S. Water Services	(1.1		)	3.2		10.7

Corporate and Other (d)(e)	19.9			6.2		(8.4		)
Total Net Income Attributable to ALLETE	$185.6			$174.1		$172.2


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


(c)	Net income in 2018 includes the recognition of profit for the sale of a wind energy facility to Montana-Dakota Utilities.


(d)	Net income in 2017 included 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.



As of December 31	2019		2018
Millions
Assets
Regulated Operations	$4,130.8		$3,952.5

ALLETE Clean Energy	1,001.5		606.6
U.S. Water Services (a)	—		295.8

Corporate and Other	350.5		310.1
Total Assets		$5,482.8		$5,165.0
Capital Expenditures
Regulated Operations	$230.9		$211.9

ALLETE Clean Energy	385.6		89.7
U.S. Water Services (a)	—		5.0

Corporate and Other	10.1		12.0
Total Capital Expenditures		$626.6		$318.6

(a) On March 26, 2019, ALLETE sold U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)



Year Ended December 31	2019			2018			2017
Millions
Depreciation and Amortization
Regulated Operations		$159.4			$158.0			$132.6

ALLETE Clean Energy	26.8			24.4			23.4
U.S. Water Services	2.3			10.2			9.8

Corporate and Other	13.5			13.0			11.7
Total Depreciation and Amortization		$202.0			$205.6			$177.5
Operating Expenses – Other (a)
Corporate and Other	—			$(2.0)			$(0.7)
Total Operating Expenses – Other	—			$(2.0)			$(0.7)
Interest Expense (b)
Regulated Operations		$58.9			$60.2			$57.0

ALLETE Clean Energy	2.8			3.6			4.2
U.S. Water Services	0.2			1.5			1.6

Corporate and Other	8.0			7.3			10.3

Eliminations	(5.0		)	(4.7		)	(5.3		)
Total Interest Expense		$64.9			$67.9			$67.8
Equity Earnings
Regulated Operations		$21.7			$17.5			$22.5
Income Tax Expense (Benefit) (c)
Regulated Operations (d)	$(7.1)			$(15.5)				$27.2

ALLETE Clean Energy	(11.9		)	(1.0		)	(14.2		)
U.S. Water Services	(0.4		)	1.0			(7.8		)

Corporate and Other (d)(e)	12.8			—			9.5
Total Income Tax Expense (Benefit)	$(6.6)			$(15.5)				$14.7


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


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

(c)

(d)

Operations and Significant Accounting Policies - Business Segments (Details)
$ in Millions

12 Months Ended

Dec. 31, 2019

USD ($)

Customers

Dec. 31, 2018

Business Segments [Line Items]

Number of Reportable Segments

Square Butte [Member] | Square Butte PPA [Member]

Business Segments [Line Items]

Minnesota Power Output Entitlement (MW) | MW

227.5

Square Butte [Member] | Square Butte [Member] | Square Butte PPA [Member]

Business Segments [Line Items]

Generating Capacity Counterparty Owned (MW) | MW

455

Minnesota Power [Member] | Square Butte [Member] | Square Butte [Member] | Square Butte PPA [Member]

Business Segments [Line Items]

Minnesota Power Output Entitlement (Percent)

50.00%

U.S. Water Services [Member]

Business Segments [Line Items]

Approximate Proceeds from Divestiture of Business | $

$ 270

Regulated Operations [Member] | Minnesota Power [Member] | Retail Customers [Member] | Electric Rates [Member]

Business Segments [Line Items]

Number of Customers

145,000

Regulated Operations [Member] | Minnesota Power [Member] | Municipal Customers [Member] | Electric Rates [Member]

Business Segments [Line Items]

Number of Customers

Regulated Operations [Member] | SWL&P [Member] | Retail Customers [Member] | Electric Rates [Member]

Business Segments [Line Items]

Number of Customers

15,000

Regulated Operations [Member] | SWL&P [Member] | Retail Customers [Member] | Natural Gas [Member]

Business Segments [Line Items]

Number of Customers

13,000

Regulated Operations [Member] | SWL&P [Member] | Retail Customers [Member] | Water [Member]

Business Segments [Line Items]

Number of Customers

10,000

ALLETE Clean Energy [Member] | Diamond Spring [Member]

Business Segments [Line Items]

Generating Capacity Owned (MW) | MW

300

ALLETE Clean Energy [Member] | ALLETE Clean Energy [Member]

Business Segments [Line Items]

Generating Capacity Owned (MW) | MW

660

Generating Capacity Under Construction (MW) | MW

380

Corporate and Other [Member]

Business Segments [Line Items]

Land in Minnesota (Acres) | a

4,000

Corporate and Other [Member] | BNI Energy [Domain]

Business Segments [Line Items]

Number of Customers

Corporate and Other [Member] | BNI Energy [Domain] | Square Butte [Member]

Business Segments [Line Items]

Number of Customers

Nobles 2 [Member]

Business Segments [Line Items]

Ownership Percentage

49.00%

Business Segments [Line Items]

Generating Capacity Counterparty Owned (MW) | MW

^[1]

250

Contract Term (Years)

20 years

[1]	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Cash Paid During the Period for Interest – Net of Amounts Capitalized

$ 63.5

$ 66.0

$ 64.5

Recognition of Right-of-use Assets and Lease Liabilities

^[1]

28.7

0.0

Remeasurement of Deferred Income Taxes Resulting from the TCJA [Abstract]

Increase to Regulatory Assets

0.0

80.9

Decrease in Investment in ATC

0.0

(27.9)

Increase (Decrease) in Deferred Income Taxes

0.0

(353.6)

Increase to Regulatory Liabilities

0.0

393.6

Noncash Investing and Financing Activities [Abstract]

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

33.9

(0.1)

67.2

Reclassification of Property, Plant and Equipment to Inventory

^[2]

0.0

46.3

0.0

Costs Incurred, Capitalized Asset Retirement Obligation Costs

20.7

14.2

(15.6)

AFUDC–Equity

2.3

1.2

ALLETE Common Stock Contributed to the Defined Benefit Pension Plan

$ 0.0

$ 13.5

[1]

See Leases.

[2]

Operations and Significant Accounting Policies - Balance Sheet and Income Statement Disclosures (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

Cash and Cash Equivalents

$ 69.3

$ 69.1

$ 98.9

Restricted Cash, Noncurrent

20.4

8.6

Restricted Cash included in Prepayments and Other

2.8

1.3

2.6

Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows

92.5

79.0

110.1

$ 38.3

Accounts Receivable [Abstract]

Billed

^[1]

77.2

121.7

Unbilled

^[1]

20.1

24.4

Less: Allowance for Doubtful Accounts

^[1]

0.9

1.7

Total Accounts Receivable

96.4

144.4

Inventories – Net [Abstract]

Fuel

^[2]

25.9

26.0

Materials and Supplies

46.9

44.2

Raw Materials

^[3]

0.0

2.8

Work in Progress

^[3]

0.0

6.1

Finished Goods

^[3]

0.0

8.4

Reserve for Obsolescence

^[3]

0.0

(0.8)

Total Inventories

72.8

86.7

Impairment of Long-Lived Assets [Abstract]

Impairment of Real Estate

0.0

Indefinite-Lived Intangible Assets [Abstract]

Impairment of Intangible Assets

0.0

Other Non-Current Assets [Abstract]

Contract Asset - Noncurrent

^[4]

28.0

30.7

Financing Receivable

^[5]

0.0

10.4

Operating Lease, Right-of-Use Asset

^[6]

28.6

0.0

Real Estate Investments, Net

21.9

24.4

Restricted Cash, Noncurrent

20.4

8.6

Other Postretirement Benefit Plans

37.5

0.4

Other

80.8

77.9

Total Other Non-Current Assets

217.2

152.4

Other Current Liabilities [Abstract]

Provision for Interim Rate Refunds

^[7]

0.0

40.0

PSAs

12.3

12.6

Contract with Customer, Liability, Current

^[8]

0.0

7.6

Provision for Tax Reform Refunds

^[9]

0.2

10.7

Business Combination, Contingent Consideration, Liability, Current

^[10]

0.0

3.8

Operating Lease, Liability, Current

^[11]

6.9

0.0

Other

41.0

53.8

Total Other Current Liabilities

60.4

128.5

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

160.3

138.6

PSAs

64.6

76.9

Operating Lease, Liability, Noncurrent

^[12]

21.8

0.0

Other

46.3

47.1

Total Other Non-Current Liabilities

293.0

262.6

Business Segments [Line Items]

Other – Non-utility

11.6

23.6

Operating Expenses – Other [Abstract]

Change in Fair Value of Contingent Consideration

^[13]

0.0

(2.0)

(0.7)

Total Operating Expenses – Other

$ 0.0

(2.0)

$ (0.7)

Income Taxes [Abstract]

More-Likely-Than-Not Percentage

50.00%

U.S. Water Services [Member]

Goodwill [Line Items]

Impairment of Goodwill

$ 0.0

Corporate and Other [Member]

Operating Expenses – Other [Abstract]

Total Operating Expenses – Other

^[14]

$ 0.0

$ (2.0)

$ (0.7)

[1]	On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related accounts receivable from the Consolidated Balance Sheet.
[2]	Fuel consists primarily of coal inventory at Minnesota Power.
[3]	On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related inventory items from the Consolidated Balance Sheet.
[4]	Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue.
[5]	Finance Receivable related to the 2016 sale of Ormond Crossings and Lake Swamp, which was collected in the second quarter of 2019
[6]	See Leases.
[7]	Provision for Interim Rate Refund was refunded to Minnesota Power’s retail customers in the second quarter of 2019.
[8]	Contract Liabilities consist of deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.
[9]	Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020.
[10]	Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019.
[11]	See Leases.
[12]	See Leases.
[13]	(a) Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019. (See Note 7. Fair Value.)
[14]	See Note 1. Operations and Significant Accounting Policies.

Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Details)	12 Months Ended
	Dec. 31, 2019 Customers MW	Dec. 31, 2018 Customers	Dec. 31, 2017 Customers
Disaggregation of Revenue [Line Items]
Large Power Customer Contracts	8
Revenue, Performance Obligation, Description of Payment Terms	Payment terms and conditions vary across our businesses. Aside from taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered or goods provided. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates.
Regulated Operations [Member] \| Alternative Programs [Member]
Disaggregation of Revenue [Line Items]
Revenue Collection Period Following the Annual Period it is Recognized	24 months
Regulated Operations [Member] \| Retail Electric Service [Member] \| Industrial [Member] \| Industrial Customers [Member]
Disaggregation of Revenue [Line Items]
Percentage of Total Regulated Utility kWh Sales	54.00%
U.S. Water Services [Member] \| Chemicals, Consumable Equipment and Services [Member] \| Contract [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	30-day
Long-term Contract with Customer [Member] \| Regulated Operations [Member] \| Wholesale Electric Service [Member] \| Municipal [Member] \| Municipal Customers [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	15
Long-term Contract with Customer [Member] \| Regulated Operations [Member] \| Retail Electric Service [Member] \| Industrial [Member] \| Industrial Customers [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	4 years
Contract Serving Requirement \| MW	10
Long-term Contract with Customer [Member] \| Regulated Operations [Member] \| Retail Electric Service [Member] \| Municipal Customers [Member] \| Municipal [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	3 years
Long-term Contract with Customer [Member] \| Regulated Operations [Member] \| Sale of Energy under PSA [Member] \| Other Power Suppliers [Member] \| Other Power Supplier Customers [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	2
Customer Concentration Risk [Member] \| Large Power Customers [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	8	9	9
Customer Concentration Risk [Member] \| Consolidated Operating Revenue [Member] \| Large Power Customers [Member] \| Largest Customer [Member]
Disaggregation of Revenue [Line Items]
Concentration Risk, Percentage	12.00%	10.00%	10.00%

Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Continued) (Details) - Long-term Contract with Customer [Member] - Regulated Operations [Member] $ in Millions	Dec. 31, 2019 USD ($)
Other Power Supplier Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 55
Other Power Supplier Customers [Member] \| Other Power Suppliers [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 3
Other Power Supplier Customers [Member] \| Other Power Suppliers [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Industrial Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Industrial Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Industrial Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55
Industrial Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55
Industrial Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 55
Industrial Customers [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	5 years
Revenue, Remaining Performance Obligation, Amount	$ 65

Operations and Significant Accounting Policies - Concentration of Credit Risk (Details) - Customer Concentration Risk [Member] - Large Power Customers [Member] $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) Customers	Dec. 31, 2018 USD ($) Customers	Dec. 31, 2017 Customers
Concentration Risk [Line Items]
Number of Large Power Customers \| Customers	8	9	9
Receivables from Large Power Customers \| $	$ 7.8	$ 11.7
Largest Customer [Member] \| Consolidated Operating Revenue [Member]
Concentration Risk [Line Items]
Percent of Consolidated Operating Revenue	12.00%	10.00%	10.00%

Operations and Significant Accounting Policies - Leases (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Lessee, Lease, Description [Line Items]

Lessee, Operating Lease, Residual Value Guarantee, Description

Our largest operating lease is for the dragline at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option.

Operating Lease, Right-of-Use Asset

^[1]

$ 28.6

$ 0.0

Operating Lease, Cost

9.4

Operating Lease, Payments

9.4

Operating Lease, Liability, Current

^[2]

6.9

0.0

Operating Lease, Liability, Noncurrent

^[3]

21.8

$ 0.0

Operating Lease, Liability

28.7

Residual Value of Leased Asset

$ 3.0

Vehicles and Equipment [Member]

Lessee, Lease, Description [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

4 years

Operating Lease, Weighted Average Discount Rate, Percent

3.70%

Land and Other [Member]

Lessee, Lease, Description [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

28 years

Operating Lease, Weighted Average Discount Rate, Percent

4.10%

[1]	See Leases.
[2]	See Leases.
[3]	See Leases.

Operations and Significant Accounting Policies - Lease Maturities (Details) - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Leases Maturities [Abstract]

$ 6.6

6.0

5.0

3.2

2.9

11.5

Total Lease Payments Due

35.2

Less: Imputed Interest

6.5

Total Lease Obligations

28.7

Less: Current Lease Obligations

^[1]

6.9

$ 0.0

Long-term Lease Obligations

^[2]

$ 21.8

$ 0.0

[1]	See Leases.
[2]	See Leases.

Property, Plant and Equipment (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment – Net

$ 4,377.0

$ 3,904.4

Costs Incurred, Capitalized Asset Retirement Obligation Costs

20.7

14.2

$ (15.6)

Asset Retirement Obligation [Roll Forward]

Beginning Obligation

138.6

122.7

Accretion

7.2

7.0

Liabilities Recognized

1.4

Liabilities Settled

(4.6)

(5.3)

Revisions in Estimated Cash Flows

17.7

Ending Obligation

160.3

138.6

$ 122.7

Regulated Operations [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment in Service

4,555.8

4,490.6

Construction Work in Progress

383.6

251.1

Accumulated Depreciation

(1,635.3)

(1,549.6)

Property, Plant and Equipment – Net

$ 3,304.1

3,192.1

Regulated Operations [Member] | Generation [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

5 years

Regulated Operations [Member] | Generation [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

50 years

Regulated Operations [Member] | Transmission [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

52 years

Regulated Operations [Member] | Transmission [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

71 years

Regulated Operations [Member] | Distribution [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

19 years

Regulated Operations [Member] | Distribution [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

68 years

ALLETE Clean Energy [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment in Service

$ 686.0

488.4

Construction Work in Progress

351.3

164.5

Accumulated Depreciation

(86.8)

(73.0)

Property, Plant and Equipment – Net

$ 950.5

579.9

ALLETE Clean Energy [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

5 years

ALLETE Clean Energy [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

35 years

U.S. Water Services [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment in Service

^[1]

$ 0.0

30.1

Accumulated Depreciation

^[1]

0.0

(14.0)

Property, Plant and Equipment – Net

^[1]

$ 0.0

16.1

U.S. Water Services [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

5 years

U.S. Water Services [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

39 years

Corporate and Other [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment in Service

^[2]

$ 231.9

214.3

Construction Work in Progress

^[2]

3.8

6.6

Accumulated Depreciation

^[2]

(113.3)

(104.6)

Property, Plant and Equipment – Net

^[2]

$ 122.4

$ 116.3

Corporate and Other [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

3 years

Corporate and Other [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

50 years

[1]	On March 26, 2019, ALLETE completed the sale of U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)
[2]	Primarily includes BNI Energy and a small amount of non-rate base generation.

Jointly-Owned Facilities and Assets (Details) $ in Millions	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)
Jointly-Owned Facilities and Assets [Line Items]
Plant in Service	$ 763.7	$ 751.1
Accumulated Depreciation	272.4	240.9
Construction Work in Progress	5.7	6.4
Transmission [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Assets [Line Items]
Plant in Service	101.0	101.0
Accumulated Depreciation	13.5	11.0
Construction Work in Progress	$ 0.0	$ 0.0
Transmission [Member] \| CapX2020 Projects [Member] \| Minimum [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	9.30%	9.30%
Transmission [Member] \| CapX2020 Projects [Member] \| Maximum [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	14.70%	14.70%
Boswell Unit 4 [Member] \| Jointly-Owned Electricity Generation Plant [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	80.00%	80.00%
Generating Capacity Jointly Owned (MW) \| MW	585
Plant in Service	$ 662.7	$ 650.1
Accumulated Depreciation	258.9	229.9
Construction Work in Progress	$ 5.7	$ 6.4
Boswell Unit 4 [Member] \| Jointly-Owned Electricity Generation Plant [Member] \| Minnesota Power [Member]
Jointly-Owned Facilities and Assets [Line Items]
Minnesota Power Ownership %	80.00%
Boswell Unit 4 [Member] \| Jointly-Owned Electricity Generation Plant [Member] \| WPPI Energy [Member]
Jointly-Owned Facilities and Assets [Line Items]
WPPI Energy Ownership %	20.00%

Regulatory Matters - Electric Rates (Details) $ in Millions			12 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Nov. 01, 2019 USD ($)	Dec. 20, 2018	Dec. 31, 2019 USD ($) Customers Years MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
PSCW [Member] \| 2018 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity		10.40%
Approved Equity Ratio		55.00%
Approved Rate Increase - Amount			$ 3.0
Electric Rates [Member] \| MPUC [Member] \| Minnesota Cost Recovery Riders [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Revenue from Cost Recovery Riders			$ 31.8	$ 103.8	$ 96.9
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity				9.25%
Approved Equity Ratio				53.81%
Electric Rates [Member] \| MPUC [Member] \| 2020 Minnesota General Rate Review [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase	10.60%
Requested Return on Equity	10.05%
Requested Equity Ratio	53.81%
Annual Additional Revenue Generated from Requested Final Rate Increase	$ 66.0
Public Utilities, Interim Rate Increase (Decrease), Amount	$ 36.1
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase - Amount				$ 13.0
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers			15
Notice Required to Terminate (Years) \| Years			3
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contract (Cost-Based Formula Methodology for Entire Term) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers			2
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (expire December 2024) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers			14
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contract (Termination Effective June 2019) [Member]
Regulatory Matters [Line Items]
Average Customer Demand (MW) \| MW			29

Regulatory Matters - Integrated Resource Plan (Details) $ in Millions	Jul. 28, 2017 MW	Dec. 31, 2019 USD ($)	Aug. 22, 2018 MW
Minnesota Power [Member] \| Nemadji Trail Energy Center [Member]
Regulatory Matters [Line Items]
Estimated Capital Expenditures, Including Past Expenditures \| $		$ 350
Maximum [Member] \| Minnesota Power [Member] \| Nemadji Trail Energy Center [Member]
Regulatory Matters [Line Items]
Estimated Capital Expenditures, Including Past Expenditures \| $		700
Capital Cost Spent to Date \| $		$ 12
MPUC [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Output Being Purchased (MW)	250
MPUC [Member] \| Natural Gas-Fired [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Expected Output Entitlement (Percent)	50.00%
MPUC [Member] \| Natural Gas-Fired [Member] \| Minimum [Member] \| Resource Package [Member] \| Jointly Owned by ALLETE and Dairyland Power Cooperative [Member] \| Natural Gas PPA [Member] \| Combined-Cycle Natural Gas-Fired Generating Facility [Member] \| Jointly-Owned Electricity Generation Plant [Member]
Regulatory Matters [Line Items]
Generating Capacity Jointly Owned (MW)	525
MPUC [Member] \| Natural Gas-Fired [Member] \| Maximum [Member] \| Resource Package [Member] \| Jointly Owned by ALLETE and Dairyland Power Cooperative [Member] \| Natural Gas PPA [Member] \| Combined-Cycle Natural Gas-Fired Generating Facility [Member] \| Jointly-Owned Electricity Generation Plant [Member]
Regulatory Matters [Line Items]
Generating Capacity Jointly Owned (MW)	625
MPUC [Member] \| Wind Turbine Generators [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Nobles 2 [Member] \| Nobles 2 [Member]
Regulatory Matters [Line Items]
Generating Capacity Counterparty Owned (MW)	250		250

Regulatory Matters - Conservation Improvement Program (CIP) (Details) - MPUC [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CIP Triennial Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Investment Goal	$ 10.5	$ 10.3
CIP Actual Spending	8.3	9.0	$ 8.1
CIP Investment Goal, Year Two	10.5
CIP Consolidated Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Financial Incentive	$ 2.8	$ 3.0
Minimum [Member]
Regulatory Matters [Line Items]
CIP Spending Minimum - Percentage	1.50%

Regulatory Matters - Minnesota Solar Energy Standard (Details) - MPUC [Member]	Dec. 31, 2019 MW
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
Minnesota Solar Energy Standard - Camp Ripley Project [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	10
Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Counterparty Owned (MW)	1
Minnesota Solar Energy Standard - Community Solar Garden Project - Owned and Operated [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	0.04
Minimum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
Minnesota Solar Energy Standard - Small Scale Solar Mandate Percentage	10.00%
Maximum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.04

Regulatory Matters - Regulatory Assets and Liabilities (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Regulatory Assets and Liabilities [Line Items]

Regulatory Assets and Liabilities Currently Earning a Return

With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets are currently earning a return.

Non-Current Regulatory Assets

$ 420.5

$ 389.5

Current Regulatory Liability

1.9

55.1

Non-Current Regulatory Liabilities

560.3

512.1

Total Regulatory Liabilities

562.2

567.2

Provision for Interim Rate Refund [Domain]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Liability

^[1],[2]

0.0

40.0

Provision for Tax Reform Refund [Domain]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Liability

^[1],[3]

0.2

10.7

Transmission Formula Rates [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Liability

1.7

4.4

Non-Current Regulatory Liabilities

0.0

1.6

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[4]

407.2

396.4

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[5]

79.3

64.4

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[6]

35.5

25.1

Pension and Other Postretirement Plans Costs [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[7]

17.0

0.0

North Dakota Investment Tax Credits [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[8]

12.3

14.7

Conservation Improvement Program [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[9]

5.4

1.5

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[10]

0.0

6.9

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

3.6

1.5

Pension and Other Postretirement Plans Costs [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[7]

212.9

218.5

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[4]

123.4

105.5

Asset Retirement Obligation [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[11]

32.0

32.6

Boswell 1 & 2 [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[12]

10.7

16.3

Manufactured Gas Plant [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[13]

8.2

8.0

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

4.8

5.0

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

3.8

3.6

Regulatory Clause Revenues, under-recovered [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[10]

$ 24.7

$ 0.0

Rider Revenue Recovery Collection Period (Years)

2 years

[1]	Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.
[2]	This amount was refunded to Minnesota Power’s regulated retail customers in the second quarter of 2019.
[3]	Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020.
[4]	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The balances will primarily decrease over the remaining life of the related temporary differences.
[5]	Wholesale and retail contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.
[6]	Non-legal plant removal obligations included in retail customer rates that have not yet been incurred.
[7]	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)
[8]	North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers through future renewable cost recovery rider filings as the tax credits are utilized.
[9]	The conservation improvement program regulatory liability represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future refund over the next year following MPUC approval.
[10]	The cost recovery rider regulatory assets and liabilities are revenue not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL. The cost recovery rider regulatory assets as of December 31, 2019, will be recovered within the next two years.
[11]	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
[12]	In December 2018, Minnesota Power retired Boswell Units 1 and 2 and reclassified the remaining net book value from property, plant and equipment to a regulatory asset on the Consolidated Balance Sheet. The remaining net book value is currently included in Minnesota Power’s rate base and Minnesota Power is earning a return on the outstanding balance.
[13]	The manufactured gas plant regulatory asset represents costs of remediation for a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. We expect recovery of these remediation costs to be allowed by the PSCW in rates over time.

Equity Investments (Details)
$ in Millions

12 Months Ended

Jan. 31, 2020

USD ($)

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

ALLETE's Investment in ATC [Roll Forward]

Equity Investment Beginning Balance

$ 161.1

Cash Investments

37.9

$ 39.2

$ 7.8

Equity Earnings

21.7

17.5

22.5

Equity Investment Ending Balance

197.6

161.1

Income Statement Data [Abstract]

ALLETE's Equity in Net Income

$ 21.7

17.5

22.5

ATC [Member]

Equity Investments [Line Items]

Ownership Percentage

8.00%

Expected Additional Investment in 2020

$ 2.7

ALLETE's Investment in ATC [Roll Forward]

Equity Investment Beginning Balance

128.1

118.7

Cash Investments

6.6

6.2

Equity Earnings

21.7

17.5

22.5

Distributed ATC Earnings

(16.1)

(15.2)

Amortization from the Remeasurement of Deferred Income Taxes for Equity Method Investments

1.3

0.9

Equity Investment Ending Balance

141.6

128.1

118.7

Balance Sheet Data [Abstract]

Current Assets

84.6

87.2

Non-Current Assets

5,244.3

4,928.8

Total Assets

5,328.9

5,016.0

Current Liabilities

502.6

640.0

Long-Term Debt

2,312.8

2,014.0

Other Non-Current Liabilities

298.9

295.3

Members' Equity

2,214.6

2,066.7

Total Liabilities and Members' Equity

5,328.9

5,016.0

Income Statement Data [Abstract]

Revenue

744.4

690.5

721.6

Operating Expense

373.5

358.7

344.9

Other Expense

110.5

108.3

104.1

Net Income

260.4

223.5

272.6

ALLETE's Equity in Net Income

$ 21.7

17.5

$ 22.5

Authorized Return on Equity

9.88%

Authorized Return on Equity, Including Incentive Adder

10.38%

ATC [Member] | Subsequent Event [Member]

ALLETE's Investment in ATC [Roll Forward]

Cash Investments

$ 0.4

Nobles 2 [Member]

Equity Investments [Line Items]

Ownership Percentage

49.00%

Expected Additional Investment in 2020

$ 115.0

ALLETE's Investment in ATC [Roll Forward]

Equity Investment Beginning Balance

33.0

Cash Investments

31.3

Equity Investment Ending Balance

56.0

$ 33.0

Nobles 2 [Member] | Minimum [Member]

Income Statement Data [Abstract]

Estimated Project Cost

350.0

Nobles 2 [Member] | Maximum [Member]

Income Statement Data [Abstract]

Estimated Project Cost

400.0

Expected Tax Equity Financing

$ 125.0

Equity Investments [Line Items]

Generating Capacity Counterparty Owned (MW) | MW

^[1]

250

Contract Term (Years)

20 years

[1]	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.

Equity Investments Equity Investment in Nobles 2 (Details)
$ in Millions

12 Months Ended

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Equity Investments [Line Items]

Equity Investments

$ 197.6

$ 161.1

Proceeds from Equity Method Investment, Distribution, Return of Capital

(8.3)

0.0

$ 0.0

Cash Investments

$ 37.9

39.2

$ 7.8

Nobles 2 [Member]

Equity Investments [Line Items]

Equity Method Investment, Ownership Percentage

49.00%

Equity Investments

$ 56.0

$ 33.0

Cash Investments

31.3

Expected Additional Investment in 2020

$ 115.0

Equity Investments [Line Items]

Generating Capacity Counterparty Owned (MW) | MW

^[1]

250

Contract Term (Years)

20 years

Minimum [Member] | Nobles 2 [Member]

Equity Investments [Line Items]

Estimated Project Cost

$ 350.0

Maximum [Member] | Nobles 2 [Member]

Equity Investments [Line Items]

Expected Tax Equity Financing

125.0

Estimated Project Cost

$ 400.0

[1]	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.

Goodwill and Intangible Assets - Intangible Assets (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

$ 58.2

Amortization

(1.5)

$ (5.6)

Finite-Lived Intangible Assets, Other Changes

^[1]

55.7

Ending Balance

1.0

58.2

Intangible Assets [Abstract]

Total Intangible Assets

1.0

74.8

Total Intangible Assets, Amortization

(1.5)

(5.6)

Intangible Assets, Other Changes

^[1]

72.3

Trademarks and Trade Names [Member]

Indefinite-Lived Intangible Assets [Roll Forward]

Beginning Balance

16.6

Indefinite-Lived Intangible Assets, Other Changes

^[1]

16.6

Ending Balance

0.0

16.6

Customer Relationships [Member]

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

50.7

Amortization

(1.1)

Finite-Lived Intangible Assets, Other Changes

^[1]

49.6

Ending Balance

0.0

50.7

Intangible Assets [Abstract]

Total Intangible Assets, Amortization

(1.1)

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

^[2]

7.5

Amortization

^[2]

(0.4)

Finite-Lived Intangible Assets, Other Changes

^[1],[2]

6.1

Ending Balance

^[2]

1.0

$ 7.5

Intangible Assets [Abstract]

Total Intangible Assets, Amortization

^[2]

$ (0.4)

[1]	On March 26, 2019, ALLETE completed the sale of U.S. Water Services which resulted in the removal of the related intangible assets from the Consolidated Balance Sheet.
[2]	Developed Technology and Other includes land easements and trade names with finite lives.

Fair Value - Recurring Fair Value Measures (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Liabilities [Abstract]

Activity in Level 3

$ (3.8)

Debt Securities, Available-for-sale, Maturity, Allocated and Single Maturity Date, within One Year, Fair Value

2.1

Available-for-sale Securities, Debt Maturities, After One Year Through Three Years, Fair Value

7.2

Available-for-sale Securities, Debt Maturities, After Three Years Through Five Years, Fair Value

0.0

Available-for-sale Securities, Debt Maturities, After Five Years, Fair Value

0.4

Recurring Fair Value Measures [Member]

Investments [Abstract]

Available-for-sale – Equity Securities

^[1]

11.1

$ 12.2

Available-for-sale – Corporate and Governmental Debt Securities

^[1]

9.7

^[2]

8.0

Cash Equivalents

^[1]

0.9

1.0

Total Fair Value of Assets

21.7

21.2

Liabilities [Abstract]

Deferred Compensation

21.2

^[3]

19.8

^[4]

U.S. Water Services Contingent Consideration

^[4]

3.8

Total Fair Value of Liabilities

21.2

23.6

Total Net Fair Value of Assets (Liabilities)

0.5

(2.4)

Fair Value Hierarchy Transfers, All Levels

0.0

Recurring Fair Value Measures [Member] | Level 1 [Member]

Investments [Abstract]

Available-for-sale – Equity Securities

^[1]

11.1

12.2

Available-for-sale – Corporate and Governmental Debt Securities

^[1]

0.0

^[2]

0.0

Cash Equivalents

^[1]

0.9

1.0

Total Fair Value of Assets

12.0

13.2

Liabilities [Abstract]

Deferred Compensation

0.0

^[3]

0.0

^[4]

U.S. Water Services Contingent Consideration

^[4]

0.0

Total Fair Value of Liabilities

0.0

Total Net Fair Value of Assets (Liabilities)

12.0

13.2

Recurring Fair Value Measures [Member] | Level 2 [Member]

Investments [Abstract]

Available-for-sale – Equity Securities

^[1]

0.0

Available-for-sale – Corporate and Governmental Debt Securities

^[1]

9.7

^[2]

8.0

Cash Equivalents

^[1]

0.0

Total Fair Value of Assets

9.7

8.0

Liabilities [Abstract]

Deferred Compensation

21.2

^[3]

19.8

^[4]

U.S. Water Services Contingent Consideration

^[4]

0.0

Total Fair Value of Liabilities

21.2

19.8

Total Net Fair Value of Assets (Liabilities)

(11.5)

(11.8)

Recurring Fair Value Measures [Member] | Level 3 [Member]

Investments [Abstract]

Available-for-sale – Equity Securities

^[1]

0.0

Available-for-sale – Corporate and Governmental Debt Securities

^[1]

0.0

^[2]

0.0

Cash Equivalents

^[1]

0.0

Total Fair Value of Assets

0.0

Liabilities [Abstract]

Deferred Compensation

0.0

^[3]

0.0

^[4]

U.S. Water Services Contingent Consideration

^[4]

3.8

Total Fair Value of Liabilities

0.0

3.8

Total Net Fair Value of Assets (Liabilities)

$ 0.0

$ (3.8)

[1]	Included in Other Non-Current Assets on the Consolidated Balance Sheet.
[2]	As of December 31, 2019, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $2.1 million, in one year to less than three years was $7.2 million, in three years to less than five years was zero and in five or more years was $0.4 million.
[3]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

Fair Value - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Recurring Fair Value Measure, Unobservable Inputs, Period Increase (Decrease)	$ 3.8
Equity Investments	197.6	$ 161.1
ATC [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Equity Investments	141.6	128.1	$ 118.7
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] \| Corporate and Other [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Impairment of Long-Lived Assets Held-for-use	0.0
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] \| ATC [Member] \| Regulated Operations [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]
Equity Method Investment, Indicators of Impairment	$ 0.0	$ 0.0

Short-Term and Long-Term Debt - Short-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 10, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Short-Term Debt - Outstanding	$ 212.9		$ 57.5
Short-Term Debt - Unamortized Debt Issuance Costs	0.4
Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	407.0	$ 400.0	407.0
Line of Credit Facility Additional Borrowing Capacity		150.0
Standby Letters of Credit Outstanding	62.0		18.4
Draws Outstanding	0.0		$ 0.0
Letters of Credit Maximum Issuances		$ 100.0
ALLETE Amended and Restated Credit Agreement [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	$ 400.0

Short-Term and Long-Term Debt - Long-Term Debt (Details) $ in Millions				12 Months Ended
	Jan. 10, 2020 USD ($)	Aug. 14, 2019 USD ($)	Mar. 01, 2019 USD ($)	Dec. 31, 2019 USD ($) Years	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
Long-Term Debt				$ 1,400.9	$ 1,428.5
Long-Term Debt - Unamortized Debt Issuance Costs				8.4
Debt Instrument [Abstract]
Long-Term Debt Maturing in 2020				213.3
Long-Term Debt Maturing in 2021				98.6
Long-Term Debt Maturing in 2022				88.8
Long-Term Debt Maturing in 2023				88.8
Long-Term Debt Maturing in 2024				73.5
Long-Term Debt Maturing Thereafter				$ 1,059.6
First Mortgage Bonds - 4.08% Due March 2029 [Member]
Debt Instrument [Abstract]
Proceeds from Issuance of First Mortgage Bond			$ 70.0
Interest Rate			4.08%	4.08%
Camp Ripley Financing [Member]
Debt Instrument [Abstract]
Annual Financing Payment				$ 1.4
Financing Renewal Term (Years) \| Years				2
Purchase Option				$ 4.0
ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]
Debt Instrument [Abstract]
Interest Rate				3.11%
ALLETE Term Loan Variable Rate Due 2020 [Member]
Debt Instrument [Abstract]
Debt Instrument, Description of Variable Rate Basis				LIBOR
Debt Instrument, Basis Spread on Variable Rate				1.025%
ALLETE Bonds 4.07% Due April 2048 [Member]
Debt Instrument [Abstract]
Interest Rate				4.07%
Unsecured Term Loan Due in 2020 [Member]
Debt Instrument [Abstract]
Proceeds from Issuance of Unsecured Debt		$ 110.0
Debt Instrument, Description of Variable Rate Basis		LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.025%
ALLETE Bonds 4.47% Due March 2049 [Member]
Debt Instrument [Abstract]
Proceeds from Issuance of First Mortgage Bond			$ 30.0
Interest Rate			4.47%	4.47%
Subsequent Event [Member] \| Unsecured Term Loan Due in 2021 [Member]
Debt Instrument [Line Items]
Unsecured Term Loan, Amount	$ 200.0
Debt Instrument [Abstract]
Proceeds from Issuance of Unsecured Debt	60.0
Debt Instrument, Unused Borrowing Capacity, Amount	$ 140.0
Debt Instrument, Description of Variable Rate Basis	LIBOR
Debt Instrument, Basis Spread on Variable Rate	0.55%

Short-Term and Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Mar. 01, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term Debt	$ 1,622.6		$ 1,495.2
Unamortized Debt Issuance Costs	(8.8)		(9.2)
Total Long-Term Debt	1,613.8		1,486.0
Less: Due Within One Year	212.9		57.5
Net Long-Term Debt	$ 1,400.9		1,428.5
First Mortgage Bonds - 8.17% Series Due 2019 [Member]
Debt Instrument [Line Items]
Interest Rate	8.17%
Long-term Debt	$ 0.0		42.0
First Mortgage Bonds - 5.28% Series Due 2020 [Member]
Debt Instrument [Line Items]
Interest Rate	5.28%
Long-term Debt	$ 35.0		35.0
First Mortgage Bonds - 2.80% Series Due 2020 [Member]
Debt Instrument [Line Items]
Interest Rate	2.80%
Long-term Debt	$ 40.0		40.0
First Mortgage Bonds - 4.85% Series Due 2021 [Member]
Debt Instrument [Line Items]
Interest Rate	4.85%
Long-term Debt	$ 15.0		15.0
First Mortgage Bonds - 3.02% Series Due 2021 [Member]
Debt Instrument [Line Items]
Interest Rate	3.02%
Long-term Debt	$ 60.0		60.0
First Mortgage Bonds - 3.40% Series Due 2022 [Member]
Debt Instrument [Line Items]
Interest Rate	3.40%
Long-term Debt	$ 75.0		75.0
First Mortgage Bonds - 6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Interest Rate	6.02%
Long-term Debt	$ 75.0		75.0
First Mortgage Bonds - 3.69% Series Due 2024 [Member]
Debt Instrument [Line Items]
Interest Rate	3.69%
Long-term Debt	$ 60.0		60.0
First Mortgage Bonds - 4.90% Series Due 2025 [Member]
Debt Instrument [Line Items]
Interest Rate	4.90%
Long-term Debt	$ 30.0		30.0
First Mortgage Bonds - 5.10% Series Due 2025 [Member]
Debt Instrument [Line Items]
Interest Rate	5.10%
Long-term Debt	$ 30.0		30.0
First Mortgage Bonds - 3.20% Series Due 2026 [Member]
Debt Instrument [Line Items]
Interest Rate	3.20%
Long-term Debt	$ 75.0		75.0
First Mortgage Bonds - 5.99% Series Due 2027 [Member]
Debt Instrument [Line Items]
Interest Rate	5.99%
Long-term Debt	$ 60.0		60.0
First Mortgage Bonds - 3.30% Series Due 2028 [Member]
Debt Instrument [Line Items]
Interest Rate	3.30%
Long-term Debt	$ 40.0		40.0
First Mortgage Bonds - 4.08% Due March 2029 [Member]
Debt Instrument [Line Items]
Interest Rate	4.08%	4.08%
Long-term Debt	$ 70.0		0.0
First Mortgage Bonds - 3.74% Series Due 2029 [Member]
Debt Instrument [Line Items]
Interest Rate	3.74%
Long-term Debt	$ 50.0		50.0
First Mortgage Bonds - 3.86% Series Due 2030 [Member]
Debt Instrument [Line Items]
Interest Rate	3.86%
Long-term Debt	$ 60.0		60.0
First Mortgage Bonds - 5.69% Series Due 2036 [Member]
Debt Instrument [Line Items]
Interest Rate	5.69%
Long-term Debt	$ 50.0		50.0
First Mortgage Bonds - 6.00% Series Due 2040 [Member]
Debt Instrument [Line Items]
Interest Rate	6.00%
Long-term Debt	$ 35.0		35.0
First Mortgage Bonds - 5.82% Series Due 2040 [Member]
Debt Instrument [Line Items]
Interest Rate	5.82%
Long-term Debt	$ 45.0		45.0
First Mortgage Bonds - 4.08% Series Due 2042 [Member]
Debt Instrument [Line Items]
Interest Rate	4.08%
Long-term Debt	$ 85.0		85.0
First Mortgage Bonds - 4.21% Series Due 2043 [Member]
Debt Instrument [Line Items]
Interest Rate	4.21%
Long-term Debt	$ 60.0		60.0
First Mortgage Bonds - 4.95% Series Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate	4.95%
Long-term Debt	$ 40.0		40.0
First Mortgage Bonds - 5.05% Series Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate	5.05%
Long-term Debt	$ 40.0		40.0
First Mortgage Bonds - 4.39% Series Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate	4.39%
Long-term Debt	$ 50.0		50.0
ALLETE Bonds 4.07% Due April 2048 [Member]
Debt Instrument [Line Items]
Interest Rate	4.07%
Long-term Debt	$ 60.0		60.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	13.5		13.5
ALLETE Term Loan Variable Rate Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 110.0		10.0
Debt Instrument, Description of Variable Rate Basis	LIBOR
Debt Instrument, Basis Spread on Variable Rate	1.025%
Armenia Mountain Senior Secured Notes 3.26% Due 2024 [Member]
Debt Instrument [Line Items]
Interest Rate	3.26%
Long-term Debt	$ 47.8		57.2
A415SeriesDue2028 [Member]
Debt Instrument [Line Items]
Interest Rate	4.15%
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 27.8		27.8
ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]
Debt Instrument [Line Items]
Interest Rate	3.11%
Long-term Debt	$ 80.0		80.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 15.0		15.0
SWL&P First Mortgage Bonds 4.14% Series Due 2048 [Member]
Debt Instrument [Line Items]
Interest Rate	4.14%
Long-term Debt	$ 12.0		12.0
Other Long-Term Debt, 3.11% – 5.75% Due 2020 – 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 46.5		67.7
ALLETE Bonds 4.47% Due March 2049 [Member]
Debt Instrument [Line Items]
Interest Rate	4.47%	4.47%
Long-term Debt	$ 30.0		$ 0.0
Minimum [Member] \| Other Long-Term Debt, 3.11% – 5.75% Due 2020 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate	3.11%
Maximum [Member] \| Other Long-Term Debt, 3.11% – 5.75% Due 2020 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate	5.75%

Commitments, Guarantees and Contingencies Minimum Payments for Certain Long-Term Commitments (Details)
$ in Millions

12 Months Ended

Dec. 31, 2019

USD ($)

Leasing Agreements [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

Minimum Payments in 2019

$ 292.7

Minimum Payments in 2020

0.0

Minimum Payments in 2021

0.0

Minimum Payments in 2022

0.0

Minimum Payments in 2023

0.0

Minimum Payments Thereafter

0.0

Easements [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

Minimum Payments in 2019

5.0

^[1]

Minimum Payments in 2020

5.3

^[1]

Minimum Payments in 2021

5.4

^[1]

Minimum Payments in 2022

5.5

^[1]

Minimum Payments in 2023

5.5

^[1]

Minimum Payments Thereafter

170.4

^[1]

Long-Term Service Agreements [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

Minimum Payments in 2019

22.8

^[2]

Minimum Payments in 2020

9.6

^[2]

Minimum Payments in 2021

0.0

^[2]

Minimum Payments in 2022

0.0

^[2]

Minimum Payments in 2023

0.0

^[2]

Minimum Payments Thereafter

0.1

^[2]

PPAs [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

Minimum Payments in 2019

113.0

^[3]

Minimum Payments in 2020

122.5

^[3]

Minimum Payments in 2021

145.5

^[3]

Minimum Payments in 2022

145.6

^[3]

Minimum Payments in 2023

138.5

^[3]

Minimum Payments Thereafter

1,386.7

^[3]

Square Butte Coal-fired Unit [Member] | Square Butte PPA [Member] | Minnesota Power [Member] | Square Butte [Member] | 2020-01-01 [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

PPA Counterparty Annual Debt Service through 2024

48.7

Square Butte Coal-fired Unit [Member] | Square Butte PPA [Member] | Minnesota Power [Member] | Square Butte [Member] | 2021-01-01 [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

PPA Counterparty Annual Debt Service through 2024

48.7

Square Butte Coal-fired Unit [Member] | Square Butte PPA [Member] | Minnesota Power [Member] | Square Butte [Member] | 2024-01-01 [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

PPA Counterparty Annual Debt Service through 2024

33.6

Square Butte Coal-fired Unit [Member] | Square Butte PPA [Member] | Minnesota Power [Member] | Square Butte [Member] | 2022-01-01 [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

PPA Counterparty Annual Debt Service through 2024

48.7

Square Butte Coal-fired Unit [Member] | Square Butte PPA [Member] | Minnesota Power [Member] | Square Butte [Member] | 2023-01-01 [Member]

Minimum Annual Payments for Certain Long-Term Commitments [Line Items]

PPA Counterparty Annual Debt Service through 2024

$ 48.7

[1]	Easement obligations represent the minimum payments for our land easement agreements at our wind energy facilities.
[2]	Consists of long-term service agreements for wind energy facilities and minimum purchase commitments under coal and rail contracts.
[3]	Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with Nobles 2 commencing in 2020 as it is subject to construction of a wind energy facility. (See Power Purchase Agreements.)

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details)
MWh in Millions, $ in Millions

12 Months Ended

Dec. 31, 2019

USD ($)

MWh

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Square Butte [Member] | Square Butte PPA (expires 2026) [Member]

Power Purchase Agreements [Line Items]

PPA Counterparty Total Debt Outstanding | $

$ 280.7

Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Cost of Purchased Power | $

82.7

$ 78.0

$ 75.7

Pro Rata Share of PPA Counterparty Interest Expense | $

$ 8.3

$ 9.1

$ 9.4

Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Square Butte Coal-fired Unit [Member]

Power Purchase Agreements [Line Items]

Generating Capacity Counterparty Owned (MW)

455

Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Square Butte Coal-fired Unit [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Minnesota Power Output Entitlement (Percent)

50.00%

PPA Annual Debt Service Obligation (Percentage)

50.00%

Manitoba Hydro [Member] | Manitoba Hydro PPA (expires April 2022) [Member] | Minnesota Power [Member] | Minimum [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased (MWh) | MWh

1,000,000

Manitoba Hydro [Member] | Manitoba Hydro PPA (expires 2040) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy (MW)

133

Manitoba Hydro [Member] | Manitoba Hydro PPA Beginning June 2017 (expires May 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Capacity (MW)

Manitoba Hydro [Member] | Manitoba Hydro PPA (expires 2040) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Contract Term (Years)

20 years

Manitoba Hydro [Member] | Manitoba Hydro PPA Beginning June 2015 (expires May 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy and Capacity (MW)

Manitoba Hydro [Member] | Manitoba Hydro PPA (expires May 2035) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy and Capacity (MW)

250

Power Purchase Agreements [Line Items]

Generating Capacity Counterparty Owned (MW)

^[1]

250

Contract Term (Years)

20 years

Oliver Wind [Member] | Oliver Wind I PPA [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy (MW)

Oliver Wind [Member] | Oliver Wind II PPA [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy (MW)

Basin Electric Power Cooperative [Member] | Basin Electric Cooperative PSA June 2022 - May 2023 [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Sold Electric - Capacity (MW)

Basin Electric Power Cooperative [Member] | Basin Electric Cooperative PSA June 2023 - May 2025 [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Sold Electric - Capacity (MW)

125

Minnkota Power [Member] | Square Butte PPA (expires 2026) [Member] | Minnkota Sales Agreement [Member] | Square Butte Coal-fired Unit [Member]

Power Purchase Agreements [Line Items]

Minnesota Power Output Entitlement (Percent)

28.00%

Minnkota Power [Member] | Minnkota Power PPA (expires May 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy and Capacity (MW)

Silver Bay Power [Member] | Silver Bay Power Self-Generation [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Generating Capacity Owned (MW)

Silver Bay Power [Member] | Silver Bay Power Sales Agreement through 2031 (Years 2016-2019) [Member] | Minnesota Power [Member] | Minimum [Member]

Power Purchase Agreements [Line Items]

Output Being Sold - Electric Energy (MW)

Calpine Corporation [Member] | Calpine Corporation PPA [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Capacity (MW)

Great River Energy [Member] | Great River Energy Capacity Only PPA Beginning 2016 (expires 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Capacity (MW)

Great River Energy [Member] | Great River Energy Capacity Only PPA Beginning 2017 (expires 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Capacity (MW)

Great River Energy [Member] | Great River Energy Capacity and Energy PPA (expires May 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy and Capacity (MW)

Basin [Member] | Basin Power Sales Agreement (expires May 2028) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Sold Electric - Capacity (MW)

100

Basin [Member] | Basin PSA (expires April 2020) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Sold Electric - Energy and Capacity (MW)

100

Oconto Electric Cooperative [Member] | Oconto Electric Cooperative Power Sales Agreement [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Sold Electric - Energy and Capacity (MW)

2020-01-01 [Member] | Square Butte [Member] | Square Butte PPA (expires 2026) [Member] | Square Butte Coal-fired Unit [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

PPA Counterparty Annual Debt Service through 2024 | $

$ 48.7

[1]	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	Dec. 31, 2019 USD ($) Miles kV MW
Great Northern Transmission Line [Member]
Transmission [Line Items]
Total Project Costs Incurred to Date	$ 633.3
Manitoba Hydro [Member] \| Great Northern Transmission Line [Member]
Transmission [Line Items]
Project Costs Recovered from Counterparty	$ 339.6
Minnesota Power [Member] \| Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Total Project Cost in the U.S.	$ 325.0
Minnesota Power [Member] \| Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	$ 700.0
Manitoba Hydro PPA [Member] \| Manitoba Hydro [Member]
Transmission [Line Items]
Output Being Purchased (MW) \| MW	250

Commitments, Guarantees and Contingencies - Environmental Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Coal Combustion Residuals [Member] \| Minnesota Power [Member]
Environmental Matters [Line Items]
Expected Period for Costs of Compliance	15 years
Coal Combustion Residuals [Member] \| Minimum [Member] \| Minnesota Power [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	$ 65
Coal Combustion Residuals [Member] \| Maximum [Member] \| Minnesota Power [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	120
Manufactured Gas Plant [Member] \| SWL&P [Member] \| Superior, WI [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance (Accrued)	$ 7	$ 7
Expected Period to Incur Remediation Costs	four years

Commitments, Guarantees and Contingencies - Other Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
BNI Energy Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	$ 67.3
BNI Energy Reclamation Liability [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	64.3
BNI Energy Reclamation Liability [Member] \| Surety Bonds [Member]
Guarantor Obligations [Line Items]
Collateral	67.7
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	2.3
ALLETE Properties Development and Maintenance Obligations [Member] \| Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	4.8
Town Center District Capital Improvement Bonds [Member]
Guarantor Obligations [Line Items]
Bonds	$ 26.4
Bond Interest Rate	6.00%
Bond Term (Years)	31 years
Ownership Percentage of Benefited Property	53.00%	68.00%
Annual Assessment	$ 1.4
Palm Coast Park District Special Assessment Bonds [Member]
Guarantor Obligations [Line Items]
Bonds	$ 31.8
Bond Interest Rate	5.70%
Bond Term (Years)	31 years
Ownership Percentage of Benefited Property	0.00%	19.00%
Superior, WI [Member] \| Manufactured Gas Plant [Member] \| SWL&P [Member]
Guarantor Obligations [Line Items]
Expected Period to Incur Remediation Costs	four years

Common Stock and Earnings Per Share - Summary of Common Stock (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary of Common Stock [Line Items]
Balance, Shares	51,700	51,500
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value	$ 0.0	$ 0.0	$ 13.5
Common Stock [Member]
Summary of Common Stock [Line Items]
Balance, Shares	51,679	51,509	51,117	49,560
Balance, Equity	$ 1,436.7	$ 1,428.5	$ 1,401.4	$ 1,295.3
Employee Stock Purchase Plan, Shares	8	11	12
Employee Stock Purchase Plan, Equity	$ 0.7	$ 0.8	$ 0.8
Invest Direct, Shares	38	277	257
Invest Direct, Equity	$ 3.0	$ 20.7	$ 19.0
Options and Stock Awards, Shares	85	57	22
Options and Stock Awards, Equity	$ 1.3	$ 2.1	$ 3.6
Contributions to RSOP, Shares	39	47	50
Contributions to RSOP, Equity	$ 3.2	$ 3.5	$ 3.5
Equity Issuance Program, Shares	0	0	1,000
Equity Issuance Program, Equity			$ 65.7
Employer Contributions to Pension - Shares	0	0	200
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value			$ 13.5
Equity Issuance Program Shares Authorized			13,600
Equity Issuance Program Shares Available for Issuance	2,900
Pension Plan [Member]
Summary of Common Stock [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value	$ 0.0		$ 0.0
Pension Plan [Member] \| Common Stock [Member]
Summary of Common Stock [Line Items]
Employer Contributions to Pension - Shares			216
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value			$ 13.5

Common Stock and Earnings Per Share - Reconciliation of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share - Basic [Abstract]
Net Income	$ 49.7	$ 31.2	$ 34.2	$ 70.5	$ 61.1	$ 30.7	$ 31.3	$ 51.0	$ 41.4	$ 44.9	$ 36.9	$ 49.0	$ 185.6	$ 174.1	$ 172.2
Average Common Shares													51.6	51.3	50.8
Earnings Per Share	$ 0.96	$ 0.60	$ 0.66	$ 1.37	$ 1.19	$ 0.59	$ 0.61	$ 1.00	$ 0.81	$ 0.88	$ 0.73	$ 0.97	$ 3.59	$ 3.39	$ 3.39
Earnings Per Share - Diluted [Abstract]
Net Income (Loss) Available to Common Stockholders, Diluted													$ 185.6	$ 174.1	$ 172.2
Average Common Shares													51.7	51.5	51.0
Earnings Per Share	$ 0.96	$ 0.60	$ 0.66	$ 1.37	$ 1.18	$ 0.59	$ 0.61	$ 0.99	$ 0.81	$ 0.88	$ 0.72	$ 0.97	$ 3.59	$ 3.38	$ 3.38
Dilutive Securities (Shares)													0.1	0.2	0.2

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

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+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Income Tax Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Current Income Tax Expense [Abstract]

Federal

^[1]

$ 0.0

State

^[1]

0.1

0.3

Total Current Income Tax Expense

0.1

0.3

Deferred Income Tax Expense (Benefit) [Abstract]

Federal

^[2]

(27.8)

(26.2)

12.1

Federal - Remeasurement of Deferred Income Taxes

^[3]

0.0

(13.0)

State

21.7

11.0

15.8

Investment Tax Credit Amortization

(0.6)

(0.5)

Total Deferred Income Tax Expense (Benefit)

(6.7)

(15.8)

14.4

Total Income Tax Expense (Benefit)

$ (6.6)

$ (15.5)

$ 14.7

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

[1]	For the years ended December 31, 2019, 2018 and 2017, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. Federal and state NOLs are being carried forward to offset current and future taxable income.
[2]	For the years ended December 31, 2019, and 2018, the federal tax benefit is primarily due to production tax credits, and the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA.
[3]	For the year ended December 31, 2017, the federal deferred income tax benefit is due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Income Tax Expense - Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Abstract]

Income Before Non-Controlling Interest and Income Taxes

$ 178.9

$ 158.6

$ 186.9

Statutory Federal Income Tax Rate

21.00%

35.00%

Income Taxes Computed at Statutory Federal Rate

$ 37.6

$ 33.3

$ 65.4

Increase (Decrease) in Tax Due to: [Abstract]

State Income Taxes – Net of Federal Income Tax Benefit

17.2

8.9

10.5

Production Tax Credits

(50.7)

(45.0)

(45.1)

Regulatory Differences – Excess Deferred Tax Benefit

^[1]

(8.8)

(8.2)

1.2

U.S. Water Services Sale of Stock Basis Difference

1.7

0.0

Change in Fair Value of Contingent Consideration

0.0

(0.4)

0.0

Remeasurement of Deferred Income Taxes

^[2]

0.0

(13.0)

Other

(3.6)

(4.1)

(4.3)

Total Income Tax Expense (Benefit)

$ (6.6)

$ (15.5)

$ 14.7

Effective Tax Rate

3.70%

9.80%

7.90%

[1]	Excess deferred income taxes are being returned to customers under both the Average Rate Assumption Method and amortization periods as approved by regulators. (See Note 4. Regulatory Matters.)
[2]	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Income Tax Expense - Deferred Income Tax Assets and Liabilities (Details) - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Deferred Income Tax Assets [Abstract]

Employee Benefits and Compensation

$ 49.9

$ 62.2

Property Related

76.9

95.2

NOL Carryforwards

63.2

86.1

Tax Credit Carryforwards

395.5

349.8

Power Sales Agreements

23.7

27.5

Regulatory Liabilities

116.9

113.4

Other

23.4

25.1

Gross Deferred Income Tax Assets

749.5

759.3

Deferred Income Tax Asset Valuation Allowance

(70.0)

(66.5)

Total Deferred Income Tax Assets

679.5

692.8

Deferred Income Tax Liabilities [Abstract]

Property-Related

713.4

752.5

Regulatory Assets for Benefit Obligations

54.5

61.0

Unamortized Investment Tax Credits

31.6

32.2

Partnership Basis Differences

49.4

40.8

Regulatory Assets

35.4

29.9

Other

8.0

0.0

Total Deferred Income Tax Liabilities

892.3

916.4

Net Deferred Income Taxes

^[1]

$ 212.8

$ 223.6

[1]	Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet

Income Tax Expense - NOL and Tax Credit Carryforwards (Details) - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforwards

^[1]

$ 211.3

$ 319.0

Tax Credit Carryforwards

302.5

256.4

Tax Credit Carryforwards, Valuation Allowance

0.0

NOL Carryforwards, Valuation Allowance

0.0

State [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforwards

^[1]

274.8

305.8

Tax Credit Carryforwards

^[2]

23.4

27.4

Tax Credit Carryforwards, Valuation Allowance

$ 69.6

$ 66.0

[1]	Pre-tax amounts.
[2]	Net of a $69.6 million valuation allowance as of December 31, 2019 ($66.0 million as of December 31, 2018).

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 1.6	$ 1.7	$ 2.0
Additions for Tax Positions Related to the Current Year	0.1	0.1	0.1
Additions for Tax Positions Related to Prior Years	0.1	0.1	0.1
Reduction for Tax Positions Related to Prior Years	(0.4)	(0.2)	(0.1)
Lapse of Statute	0.0	(0.1)	(0.4)
Balance as of December 31	1.4	1.6	1.7
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.6
Unrecognized Tax Benefits, Accrued Interest	0.0	0.0	0.0
Unrecognized Tax Benefits, Penalties	0.0	$ 0.0	$ 0.0
Material Changes to Unrecognized Tax Benefits Expected During Next 12 Months	$ 0.0

Pension and Other Postretirement Benefit Plans - Contributions (Details) - USD ($) shares in Thousands, $ in Millions		12 Months Ended
	Jan. 15, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value		$ 0.0	$ 0.0	$ 13.5
ESOP Compensation Expense		$ 10.8	$ 11.4	$ 11.0
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Shares		0	0	200
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value				$ 13.5
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Cash		$ 10.4	$ 15.0	1.7
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value		$ 0.0		$ 0.0
Defined Benefit Plan - Amendments		The non-union defined benefit pension plan was frozen in 2018, and does not allow further crediting of service or earnings to the plan. Further, it is closed to new participants. The Minnesota Power union defined benefit pension plan is also closed to new participants.
Expected Employer Contributions in 2020		$ 0.0
Pension Plan [Member] \| Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Cash	$ 10.7
Pension Plan [Member] \| Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Shares				216
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value				$ 13.5
Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Employer Contributions in 2020		0.0
Postretirement Health and Life [Member] \| VEBA [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Other Postretirement Benefit Plans		0.0	0.0	0.0
Postretirement Health and Life [Member] \| Irrevocable Grantor Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Other Postretirement Benefit Plans		$ 0.0	$ 0.0	$ 0.0

Pension and Other Postretirement Benefit Plans - Obligation and Funded Status (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Change in Plan Assets [Roll Forward]

Non-Current Liabilities

$ (172.8)

$ (177.3)

Other Postretirement Benefits Plan [Member]

Defined Benefit Plan Disclosure [Line Items]

Net Loss

^[1]

(16.0)

(25.0)

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

176.0

190.1

Service Cost

3.9

4.7

$ 4.4

Interest Cost

^[2]

7.3

7.1

7.7

Plan Amendments

^[3]

(34.6)

(2.1)

Actuarial (Gain) Loss

10.5

(15.8)

Benefits Paid

(14.7)

(11.6)

Participant Contributions

3.5

3.6

Obligation, End of Year

149.8

176.0

190.1

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

154.3

171.0

Actual Return on Plan Assets

29.5

(9.6)

Employer Contribution

1.1

1.0

Defined Benefit Plan Contributions by Plan Participants, Excluding Key Employees

3.5

3.6

Benefits Paid

(14.7)

(11.7)

Fair Value, End of Year

173.7

154.3

171.0

Funded Status, End of Year

23.9

(21.7)

Non-Current Assets

37.5

0.4

Current Liabilities

(0.7)

(1.0)

Non-Current Liabilities

(12.9)

(21.1)

Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement

^[2]

(2.1)

0.0

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Net Loss

(243.4)

(230.5)

Accumulated Benefit Obligation

812.0

713.7

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

747.0

793.2

Service Cost

9.3

11.0

10.2

Interest Cost

^[4]

31.9

29.6

32.5

Plan Amendments

0.0

(1.5)

Plan Curtailments

0.0

(6.9)

Actuarial (Gain) Loss

98.3

(53.0)

Benefits Paid

(53.4)

(49.5)

Participant Contributions

20.9

24.1

Obligation, End of Year

854.0

747.0

793.2

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

598.0

628.2

Actual Return on Plan Assets

122.1

(21.2)

Employer Contribution

^[5]

32.9

40.5

Benefits Paid

(53.4)

(49.5)

Fair Value, End of Year

699.6

598.0

$ 628.2

Funded Status, End of Year

(154.4)

(149.0)

Current Liabilities

(1.6)

Non-Current Liabilities

$ (152.8)

$ (147.4)

[1]	Excludes gains, losses and contributions associated with irrevocable grantor trusts.
[2]	These components of net periodic postretirement health and life cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.
[3]	Plan design changes under the other postretirement benefit plans resulted in a decrease to the benefit obligation of $34.6 million in 2019.
[4]	These components of net periodic pension cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.
[5]	Includes Participant Contributions noted above.

Pension and Other Postretirement Benefit Plans - Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet (Details) - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Other Postretirement Benefits Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Net Loss

^[1]

$ (16.0)

$ (25.0)

Prior Service Credit

(36.3)

(4.6)

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

3.6

(1.3)

Total Net Pension Amounts Recognized in Consolidated Balance Sheet

23.9

(21.7)

Pension Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Net Loss

(243.4)

(230.5)

Prior Service Credit

1.3

1.4

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

87.7

80.1

Total Net Pension Amounts Recognized in Consolidated Balance Sheet

(154.4)

(149.0)

Trust for Benefit of Employees [Member] | Other Postretirement Benefits Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Long-term Investments

$ 19.1

$ 18.3

[1]	Excludes gains, losses and contributions associated with irrevocable grantor trusts.

Pension and Other Postretirement Benefit Plans - Components of Net Periodic Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Other Postretirement Benefits Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement

^[1]

$ (2.1)

$ 0.0

Service Cost

3.9

4.7

4.4

Interest Cost

^[1]

7.3

7.1

7.7

Expected Return on Plan Assets

^[1]

(10.5)

(10.9)

(10.5)

Amortization of Loss

^[1]

0.5

0.8

0.3

Amortization of Prior Service Cost

^[1]

(2.8)

(2.1)

(2.0)

Net Pension Cost

(3.7)

(0.4)

(0.1)

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Service Cost

9.3

11.0

10.2

Interest Cost

^[2]

31.9

29.6

32.5

Expected Return on Plan Assets

^[2]

(44.2)

(44.4)

(42.4)

Amortization of Loss

^[2]

7.5

11.4

9.9

Amortization of Prior Service Cost

^[2]

(0.1)

0.0

Net Pension Cost

$ 4.4

$ 7.5

$ 10.2

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

Pension and Other Postretirement Benefit Plans - Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ (10.6)	$ 4.7
Prior Service Credit Arising During the Period	(34.6)	(2.1)
Amortization of Prior Service Cost	2.8	2.1
Amortization of Loss	(0.5)	(0.8)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	(42.9)	3.9
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	20.4	5.8
Amortization of Prior Service Cost	0.1	0.1
Prior Service Credit Arising During the Period	0.0	(1.6)
Amortization of Loss	(7.5)	(11.4)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$ 13.0	$ (7.1)

Pension and Other Postretirement Benefit Plans - Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Plan Amendments

$ 0.0

$ (1.5)

Projected Benefit Obligation

854.0

747.0

Accumulated Benefit Obligation

812.0

713.7

Fair Value of Plan Assets

699.6

598.0

Other Postretirement Benefits Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Plan Amendments

^[1]

$ (34.6)

$ (2.1)

[1]	Plan design changes under the other postretirement benefit plans resulted in a decrease to the benefit obligation of $34.6 million in 2019.

Pension and Other Postretirement Benefit Plans - Unrecognized Postretirement Health and Life Costs (Details) - Postretirement Health and Life [Member] - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Net Loss

^[1]

$ 16.0

$ 25.0

Prior Service Credit

(36.3)

(4.6)

Total Unrecognized Postretirement Health and Life Cost

$ (20.3)

$ 20.4

[1]	Excludes gains, losses and contributions associated with irrevocable grantor trusts.

Pension and Other Postretirement Benefit Plans - Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet (Details) - Postretirement Health and Life [Member] - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Net Loss

^[1]

$ (16.0)

$ (25.0)

Prior Service Credit

36.3

4.6

Accumulated Net Periodic Benefit Cost in Excess of Contributions

3.6

(1.3)

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

$ 23.9

$ (21.7)

[1]	Excludes gains, losses and contributions associated with irrevocable grantor trusts.

Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2019 USD ($)
Pension [Member]
Estimated Future Benefit Payments [Abstract]
2020	$ 51.2
2021	50.7
2022	50.1
2023	49.8
2024	49.6
Years 2025 - 2029	239.3
Postretirement Health and Life [Member]
Estimated Future Benefit Payments [Abstract]
2020	8.6
2021	8.4
2022	8.2
2023	8.0
2024	8.0
Years 2025 - 2029	$ 40.1

Pension and Other Postretirement Benefit Plans - Defined Benefit Costs Recorded in Regulatory Long-Term Assets or Liabilities and Accumulated Other Comprehensive Income Expected to be Recognized over Next Fiscal Year (Details) $ in Millions	Dec. 31, 2019 USD ($)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 12.8
Prior Service Credit	(0.2)
Total Pension and Postretirement Health and Life Cost (Credit)	12.6
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	1.0
Prior Service Credit	(8.0)
Total Pension and Postretirement Health and Life Cost (Credit)	$ (7.0)

Pension and Other Postretirement Benefit Plans - Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Minimum [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate

4.39%

3.81%

4.53%

Maximum [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate

4.53%

3.96%

4.57%

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Costs, Future Period

6.75%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Expected Long-Term Return on Plan Assets

^[1]

7.25%

7.50%

Pension [Member] | Minimum [Member]

Assumptions Used to Determine Benefit Obligation [Abstract]

Discount Rate

3.34%

4.39%

Rate of Compensation Increase

3.70%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Rate of Compensation Increase

3.70%

Pension [Member] | Maximum [Member]

Assumptions Used to Determine Benefit Obligation [Abstract]

Discount Rate

3.47%

4.53%

Rate of Compensation Increase

4.10%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Rate of Compensation Increase

4.10%

4.30%

Postretirement Health and Life [Member]

Assumptions Used to Determine Benefit Obligation [Abstract]

Discount Rate

3.45%

4.47%

Health Care Trend Rates [Abstract]

Ultimate Trend Rate

4.50%

Year Ultimate Trend Rate Effective

2038

Postretirement Health and Life [Member] | Minimum [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Costs, Future Period

5.40%

Health Care Trend Rates [Abstract]

Trend Rate

5.00%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Expected Long-Term Return on Plan Assets

^[1]

5.80%

6.00%

Postretirement Health and Life [Member] | Maximum [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Costs, Future Period

6.75%

Health Care Trend Rates [Abstract]

Trend Rate

6.20%

6.46%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Expected Long-Term Return on Plan Assets

^[1]

7.25%

7.50%

[1]	The expected long-term rates of return used to determine net periodic benefit expense for 2020 have been reduced to 6.75 percent for pension expense and 5.40 percent to 6.75 percent for postretirement health and life expense.

Pension and Other Postretirement Benefit Plans - Sensitivity of a One Percent Change in Health Care Trend Rates (Details) - Postretirement Health and Life [Member] $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Effect of One Percent Increase on Total of Postretirement Health and Life Service and Interest Cost	$ 1.8
Effect of One Percent Increase on Postretirement Health and Life Obligation	16.5
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.4)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (13.6)

Pension and Other Postretirement Benefit Plans - Plan Asset Allocations (Details) - shares
shares in Millions

Dec. 31, 2019

Dec. 31, 2018

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

100.00%

ALLETE Common Stock Included in Pension Plan Equity Securities (Shares)

0.0

Plan Asset Target Allocations

100.00%

Pension [Member] | Equity Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

34.00%

32.00%

Plan Asset Target Allocations

32.00%

Pension [Member] | Fixed Income Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

62.00%

60.00%

Plan Asset Target Allocations

56.00%

Pension [Member] | Private Equity [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

1.00%

5.00%

Plan Asset Target Allocations

6.00%

Pension [Member] | Real Estate [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

3.00%

Plan Asset Target Allocations

6.00%

Postretirement Health and Life [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

^[1]

100.00%

Plan Asset Target Allocations

^[2]

100.00%

Postretirement Health and Life [Member] | Equity Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

^[1]

66.00%

62.00%

Plan Asset Target Allocations

^[2]

60.00%

Postretirement Health and Life [Member] | Fixed Income Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

^[1]

33.00%

34.00%

Plan Asset Target Allocations

^[2]

37.00%

Postretirement Health and Life [Member] | Private Equity [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

^[1]

1.00%

4.00%

Plan Asset Target Allocations

^[2]

0.00%

Postretirement Health and Life [Member] | Real Estate [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocations

^[1]

0.00%

Plan Asset Target Allocations

^[2]

3.00%

[1]	Includes VEBAs and irrevocable grantor trusts.
[2]	Includes VEBAs and irrevocable grantor trusts.

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures, Activity in Level 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 27.8	$ 33.2
Actual Return on Plan Assets	0.4	2.8
Purchases, Sales, and Settlements – Net	(20.2)	(8.2)
Ending Balance	8.0	27.8
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	20.8	25.5
Actual Return on Plan Assets	(1.3)	0.7
Purchases, Sales, and Settlements – Net	(1.5)	(5.4)
Ending Balance	18.0	20.8
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	6.5	8.2
Actual Return on Plan Assets	0.7	0.9
Purchases, Sales, and Settlements – Net	(5.5)	(2.6)
Ending Balance	$ 1.7	$ 6.5

Employee Stock and Incentive Plans - Stock-Based Compensation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2019 shares
Performance Shares [Member]
Stock-based Compensation [Line Items]
Vesting Period (Years)	3 years
Restricted Stock Units [Member]
Stock-based Compensation [Line Items]
Vesting Period (Years)	3 years
Employee Stock Purchase Plan (ESPP) [Member]
Stock-based Compensation [Line Items]
ESPP Discount	5.00%
Executive Long-Term Incentive Compensation Plan [Member]
Stock-based Compensation [Line Items]
Common Stock Reserved (Shares)	0.8
Shares Available for Issuance	0.7

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 3.1	$ 3.2	$ 3.1
Income Tax Benefit	0.9	0.9	0.9
Capitalized Share-Based Compensation Costs	$ 0.0	0.0	0.0
Performance Shares [Member]
Share-Based Compensation Expense [Line Items]
Performance Period (Years)	3 years
Share-Based Compensation Expense	$ 2.3	2.3	2.1
Unrecognized Compensation Cost	$ 2.2
Weighted-Average Period for Recognition (Years/Months)	1 year 7 months 6 days
Restricted Stock Units [Member]
Share-Based Compensation Expense [Line Items]
Performance Period (Years)	3 years
Share-Based Compensation Expense	$ 0.8	$ 0.9	$ 1.0
Unrecognized Compensation Cost	$ 0.9

Employee Stock and Incentive Plans - Performance Shares and Restricted Stock Units (Details) - USD ($)
$ / shares in Units, $ in Millions

1 Months Ended

12 Months Ended

Feb. 29, 2020

Jan. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Performance Shares [Member]

Stock-based Compensation [Line Items]

Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition

1 year 7 months 6 days

Number of Shares [Rollforward]

As of January 1

99,585

129,693

127,898

127,580

Granted

^[1]

60,747

66,557

50,729

Awarded

(75,943)

(58,293)

Unearned Grant Award

(40,801)

Forfeited

(14,912)

(6,469)

(9,610)

As of December 31

99,585

129,693

127,898

Performance Period (Years)

3 years

Weighted-Average Grant Date Fair Value [Abstract]

As of January 1

$ 72.78

$ 66.12

$ 58.23

$ 52.56

Granted

^[1]

63.89

76.42

62.90

Awarded

53.44

59.82

Unearned Grant Award

46.27

Forfeited

77.14

72.99

58.29

As of December 31

$ 72.78

$ 66.12

$ 58.23

Restricted Stock Units [Member]

Number of Shares [Rollforward]

As of January 1

39,943

49,771

55,248

54,728

Granted

^[2]

13,927

16,573

21,241

Awarded

(21,110)

(18,881)

(17,281)

Forfeited

(2,645)

(3,169)

(3,440)

As of December 31

39,943

49,771

55,248

Performance Period (Years)

3 years

Weighted-Average Grant Date Fair Value [Abstract]

As of January 1

$ 69.30

$ 60.74

$ 56.18

$ 51.79

Granted

^[2]

74.93

71.11

62.20

Awarded

52.44

55.78

49.72

Forfeited

72.43

64.92

56.00

As of December 31

$ 69.30

$ 60.74

$ 56.18

Subsequent Event [Member] | Performance Shares [Member]

Number of Shares [Rollforward]

Granted

22,000

Awarded

(25,000)

Performance Period (Years)

3 years

Granted, Grant Date Fair Value

$ 1.8

Awarded, Grant Date Fair Value

$ 1.6

Subsequent Event [Member] | Restricted Stock Units [Member]

Number of Shares [Rollforward]

Granted

14,000

Awarded

(15,000)

Granted, Grant Date Fair Value

$ 1.1

Awarded, Grant Date Fair Value

$ 0.9

[1]	Shares granted include accrued dividends.
[2]	Shares granted include accrued dividends.

Business Segments Business Segment (Details)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2019

USD ($)

Sep. 30, 2019

USD ($)

Jun. 30, 2019

USD ($)

Mar. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Sep. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Segment Reporting Information [Line Items]

Number of Reportable Segments

Revenues

$ 304.6

$ 288.3

$ 290.4

$ 357.2

$ 448.3

$ 348.0

$ 344.1

$ 358.2

$ 337.9

$ 362.5

$ 353.3

$ 365.6

$ 1,240.5

$ 1,498.6

$ 1,419.3

Net Income

49.7

$ 31.2

$ 34.2

$ 70.5

61.1

$ 30.7

$ 31.3

$ 51.0

$ 41.4

$ 44.9

$ 36.9

$ 49.0

185.6

174.1

172.2

Deferred Federal Income Tax Expense (Benefit), Remeasurement of Deferred Income Taxes

^[1]

0.0

13.0

Depreciation, Depletion and Amortization

202.0

205.6

177.5

Operating Expenses – Other

0.0

(2.0)

(0.7)

Interest Expense

64.9

67.9

67.8

Equity Earnings

21.7

17.5

22.5

Income Tax Expense (Benefit)

(6.6)

(15.5)

14.7

Assets

5,482.8

5,165.0

5,482.8

5,165.0

Property, Plant and Equipment, Additions

626.6

318.6

Income Tax Expense (Benefit), Due to Sale of Subsidiary

$ 10.4

Regulated Operations [Member]

Segment Reporting Information [Line Items]

Number of Operating Segments

Depreciation, Depletion and Amortization

$ 159.4

158.0

132.6

Interest Expense

^[2]

58.9

60.2

57.0

Equity Earnings

21.7

17.5

22.5

Income Tax Expense (Benefit)

^[3],[4]

(7.1)

(15.5)

27.2

Property, Plant and Equipment, Additions

230.9

211.9

Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenues

1,042.4

1,059.5

1,063.8

Net Income

^[5],[6]

154.4

131.0

128.4

Assets

$ 4,130.8

3,952.5

$ 4,130.8

3,952.5

Corporate and Other [Member]

Segment Reporting Information [Line Items]

Number of Operating Segments

Land in Minnesota (Acres) | a

4,000

Revenues

$ 105.1

107.1

123.2

Net Income

^{[5],[6],[7],[8]}

19.9

6.2

(8.4)

Deferred Federal Income Tax Expense (Benefit), Remeasurement of Deferred Income Taxes

(19.8)

Depreciation, Depletion and Amortization

13.5

13.0

11.7

Operating Expenses – Other

^[9]

0.0

(2.0)

(0.7)

Interest Expense

^[2]

8.0

7.3

10.3

Income Tax Expense (Benefit)

^[3],[4],[10]

12.8

0.0

9.5

Assets

$ 350.5

310.1

350.5

310.1

Property, Plant and Equipment, Additions

10.1

12.0

Consolidation, Eliminations [Member]

Segment Reporting Information [Line Items]

Interest Expense

^[2]

(5.0)

(4.7)

(5.3)

ALLETE Clean Energy [Member]

Segment Reporting Information [Line Items]

Revenues

59.6

159.9

80.5

Net Income

^[5],[6],[11]

12.4

33.7

41.5

Deferred Federal Income Tax Expense (Benefit), Remeasurement of Deferred Income Taxes

23.6

Depreciation, Depletion and Amortization

26.8

24.4

23.4

Interest Expense

^[2]

2.8

3.6

4.2

Income Tax Expense (Benefit)

^[3],[4]

(11.9)

(1.0)

(14.2)

Assets

1,001.5

606.6

1,001.5

606.6

Property, Plant and Equipment, Additions

385.6

89.7

U.S. Water Services [Member]

Segment Reporting Information [Line Items]

Revenues

33.4

172.1

151.8

Net Income

^[5],[6]

(1.1)

3.2

10.7

Deferred Federal Income Tax Expense (Benefit), Remeasurement of Deferred Income Taxes

9.2

Depreciation, Depletion and Amortization

2.3

10.2

9.8

Interest Expense

^[2]

0.2

1.5

1.6

Income Tax Expense (Benefit)

^[3],[4]

(0.4)

1.0

(7.8)

Assets

^[12]

$ 0.0

$ 295.8

0.0

295.8

Property, Plant and Equipment, Additions

^[12]

0.0

5.0

Gain on Sale of Affiliate, After-tax

13.2

Residential [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

139.6

139.7

127.4

Commercial [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

145.7

147.9

139.8

Municipal [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

48.6

54.9

57.9

Industrial [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

476.4

469.5

470.5

Other Power Suppliers [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

153.7

170.3

161.8

CIP Financial Incentive [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

2.8

3.0

5.5

Other [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

75.6

74.2

100.9

Long-term PSA [Member] | ALLETE Clean Energy [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

48.0

55.2

56.9

Sale of Wind Energy Facility [Member] | ALLETE Clean Energy [Member]

Segment Reporting Information [Line Items]

Sale of Wind Energy Facility

0.0

81.1

0.0

ALLETE Clean Energy Other [Member] | ALLETE Clean Energy [Member]

Segment Reporting Information [Line Items]

Revenue, Other Than Customer Revenue

11.6

23.6

Point-in-Time [Member] | U.S. Water Services [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

19.0

100.3

95.8

Contract [Member] | U.S. Water Services [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

9.2

38.3

36.2

Capital Project [Member] | U.S. Water Services [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

5.2

33.5

19.8

Long-term Contract [Member] | Corporate and Other [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

82.8

85.5

89.3

Corporate & Other - Other [Member] | Corporate and Other [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

$ 22.3

$ 21.6

33.9

MPUC [Member] | Retail Customers [Member] | Renewable Cost Recovery Rider [Member] | Electric Rates [Member] | Corporate and Other [Member]

Segment Reporting Information [Line Items]

Tax Adjustments, Settlements, and Unusual Provisions

7.9

Income Tax Expense [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Net Income

0.0

Income Tax Expense [Member] | MPUC [Member] | Renewable Cost Recovery Rider [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Income Tax Expense (Benefit)

14.0

Income Tax Expense [Member] | MPUC [Member] | Renewable Cost Recovery Rider [Member] | Corporate and Other [Member]

Segment Reporting Information [Line Items]

Income Tax Expense (Benefit)

$ (7.9)

[1]	For the year ended December 31, 2017, the federal deferred income tax benefit is due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.
[2]	Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.
[3]	In 2017, Regulated Operations includes $14.0 million of income tax expense related to North Dakota investment tax credits transferred to Corporate and Other and higher pre-tax income for 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. There was no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax benefit of $7.9 million in 2017. (See Note 4. Regulatory Matters.)
[4]	Income tax expense in 2017 included an income tax benefit of $13.0 million due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, which consisted of income tax benefits of $23.6 million for ALLETE Clean Energy and $9.2 million for U.S. Water Services as well as additional income tax expense of $19.8 million for Corporate and Other. 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. (See Note 1. Operations and Significant Accounting Policies and Note 4. Regulatory Matters.)
[5]	Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.
[6]	Net income in 2017 included a favorable impact of $13.0 million after-tax due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, which consisted of a $23.6 million after-tax benefit for ALLETE Clean Energy, a $9.2 million after-tax benefit for U.S. Water Services and a $19.8 million after-tax expense for Corporate and Other. The TCJA did not have an impact on net income for our Regulated Operations as the remeasurement of deferred income tax assets and liabilities primarily resulted in the recording of regulatory assets and liabilities. (See Note 1. Operations and Significant Accounting Policies and Note 4. Regulatory Matters.)
[7]	Net income in 2017 included 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.
[8]	On March 26, 2019, ALLETE sold U.S. Water Services. The Company recognized a gain on the sale of $13.2 million after-tax which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)
[9]	See Note 1. Operations and Significant Accounting Policies.
[10]	On March 26, 2019, ALLETE sold U.S. Water Services. The Company recognized income tax expense of $10.4 million for the gain on sale of U.S. Water Services which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)
[11]	Net income in 2018 includes the recognition of profit for the sale of a wind energy facility to Montana-Dakota Utilities.
[12]	On March 26, 2019, ALLETE sold U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Operating Revenue	$ 304.6	$ 288.3	$ 290.4	$ 357.2	$ 448.3	$ 348.0	$ 344.1	$ 358.2	$ 337.9	$ 362.5	$ 353.3	$ 365.6	$ 1,240.5	$ 1,498.6	$ 1,419.3
Operating Income	49.8	37.0	36.2	56.8	64.0	43.3	36.5	57.4	32.3	68.0	54.0	71.6	179.8	201.2	225.9
Net Income Attributable to ALLETE	$ 49.7	$ 31.2	$ 34.2	$ 70.5	$ 61.1	$ 30.7	$ 31.3	$ 51.0	$ 41.4	$ 44.9	$ 36.9	$ 49.0	$ 185.6	$ 174.1	$ 172.2
Basic Earnings Per Share of Common Stock	$ 0.96	$ 0.60	$ 0.66	$ 1.37	$ 1.19	$ 0.59	$ 0.61	$ 1.00	$ 0.81	$ 0.88	$ 0.73	$ 0.97	$ 3.59	$ 3.39	$ 3.39
Diluted Earnings Per Share of Common Stock	$ 0.96	$ 0.60	$ 0.66	$ 1.37	$ 1.18	$ 0.59	$ 0.61	$ 0.99	$ 0.81	$ 0.88	$ 0.72	$ 0.97	$ 3.59	$ 3.38	$ 3.38

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Schedule II (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Trade Accounts Receivable [Member]

Valuation and Qualifying Accounts and Reserves [Roll Forward]

Balance at Beginning of Period

$ 1.7

$ 2.1

$ 3.1

Additions, Charged to Income

(0.1)

0.9

0.8

Additions, Other Charges

0.0

Deductions from Reserves

^[1]

0.7

1.3

1.8

Balance at End of Period

0.9

1.7

2.1

Finance Receivables – Long-Term [Member]

Valuation and Qualifying Accounts and Reserves [Roll Forward]

Balance at Beginning of Period

0.0

Additions, Charged to Income

0.0

Additions, Other Charges

0.0

Deductions from Reserves

^[1]

0.0

Balance at End of Period

0.0

Deferred Tax Assets [Member]

Valuation and Qualifying Accounts and Reserves [Roll Forward]

Balance at Beginning of Period

66.5

60.0

43.0

Additions, Charged to Income

3.5

6.5

17.0

Additions, Other Charges

0.0

Deductions from Reserves

^[1]

0.0

Balance at End of Period

$ 70.0

$ 66.5

$ 60.0

[1]	Includes uncollectible accounts written-off.

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Dec. 31, 2019
Loss Contingencies [Line Items]
FERC Authorized Return on Common Equity	9.88%
FERC Authorized Return on Equity Including Incentive Adder	10.38%

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,622.6	$ 1,495.2
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,791.8	$ 1,534.6

Short-Term and Long-Term Debt - Financial Covenants (Details)	Dec. 31, 2019
Financial Covenants [Abstract]
Allowed Indebtedness to Total Capitalization Ratio	0.65
Actual Indebtedness to Total Capitalization Ratio	0.42

Goodwill and Intangible Assets Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 0.0	$ 148.5