Document and Entity Information Document - USD ($)	12 Months Ended
Document and Entity Information Document - USD ($)	Dec. 31, 2018	Feb. 01, 2019	Jun. 30, 2018
Document and Entity Information [Line Items]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Entity Tax Identification Number	410418150
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 3,959,298,983
Entity Common Stock, Shares Outstanding		51,519,442
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets [Abstract]
Cash and Cash Equivalents	$ 69.1	$ 98.9
Accounts Receivable (Less Allowance of $1.7 and $2.1)	144.4	135.1
Inventories – Net	86.7	95.9
Prepayments and Other	34.1	37.6
Total Current Assets	334.3	367.5
Property, Plant and Equipment – Net	3,904.4	3,822.4
Regulatory Assets	389.5	384.7
Equity Investments	161.1	118.7
Other Investments	49.1	53.1
Goodwill and Intangible Assets – Net	223.3	225.9
Other Non-Current Assets	103.3	107.7
Total Assets	5,165.0	5,080.0
Current Liabilities [Abstract]
Accounts Payable	149.8	136.3
Accrued Taxes	51.4	50.0
Accrued Interest	17.9	17.6
Long-Term Debt Due Within One Year	57.5	64.1
Other	128.5	83.2
Total Current Liabilities	405.1	351.2
Long-Term Debt	1,428.5	1,439.2
Deferred Income Taxes	223.6	230.5
Regulatory Liabilities	512.1	532.0
Defined Benefit Pension and Other Postretirement Benefit Plans	177.3	191.8
Other Non-Current Liabilities	262.6	267.1
Total Liabilities	3,009.2	3,011.8
Commitments, Guarantees and Contingencies (Note 11)
Shareholders' Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 51.5 and 51.1 Shares Issued and Outstanding	1,428.5	1,401.4
Accumulated Other Comprehensive Loss	(27.3)	(22.6)
Retained Earnings	754.6	689.4
Total Shareholders' Equity	2,155.8	2,068.2
Total Liabilities and Shareholders' Equity	$ 5,165.0	$ 5,080.0

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.7	$ 2.1
Common Stock [Abstract]
Common Stock, Par Value Per Share	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	51.5	51.1
Common Stock, Shares Issued	51.5	51.1

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenue [Abstract]
Contracts with Customers – Utility	$ 1,059.5	$ 1,063.8	$ 1,000.7
Contracts with Customers – Non-utility	415.5	331.9	316.7
Other – Non-utility	23.6	23.6	22.3
Total Operating Revenue	1,498.6	1,419.3	1,339.7
Operating Expenses [Abstract]
Fuel, Purchased Power and Gas - Utility	407.5	396.9	339.9
Transmission Services - Utility	69.9	71.2	65.2
Cost of Sales - Non-utility	218.0	147.5	137.4
Operating and Maintenance	340.5	344.1	340.9
Depreciation and Amortization	205.6	177.5	195.8
Taxes Other Than Income Taxes	57.9	56.9	53.8
Operating Expenses – Other	(2.0)	(0.7)	(10.3)
Total Operating Expenses	1,297.4	1,193.4	1,122.7
Operating Income	201.2	225.9	217.0
Other Income (Expense) [Abstract]
Interest Expense	(67.9)	(67.8)	(70.3)
Equity Earnings in ATC	17.5	22.5	18.5
Other	7.8	6.3	10.4
Total Other Expense	(42.6)	(39.0)	(41.4)
Income Before Non-Controlling Interest and Income Taxes	158.6	186.9	175.6
Income Tax Expense	(15.5)	14.7	19.8
Net Income	174.1	172.2	155.8
Less: Non-Controlling Interest in Subsidiaries	0.0	0.0	0.5
Net Income Attributable to ALLETE	$ 174.1	$ 172.2	$ 155.3
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	51.3	50.8	49.3
Diluted (Shares)	51.5	51.0	49.5
Basic Earnings Per Share of Common Stock	$ 3.39	$ 3.39	$ 3.15
Diluted Earnings Per Share of Common Stock	$ 3.38	$ 3.38	$ 3.14

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Comprehensive Income [Abstract]
Net Income	$ 174.1	$ 172.2	$ 155.8
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities - Net of Income Tax Expense (Benefit) of $-, $0.7 and $(0.2)	(0.1)	0.9	(0.2)
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Tax Expense (Benefit) of $0.3, $2.2 and $(2.4)	1.0	4.7	(3.5)
Total Other Comprehensive Income (Loss)	0.9	5.6	(3.7)
Total Comprehensive Income	175.0	177.8	152.1
Less: Non-Controlling Interest in Subsidiaries	0.0	0.0	0.5
Total Comprehensive Income Attributable to ALLETE	$ 175.0	$ 177.8	$ 151.6

- 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 Comprehensive Income Parentheticals - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Unrealized Gain (Loss) on Securities, Income Tax Expense (Benefit)	$ 0.0	$ 0.7	$ (0.2)
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Tax Expense (Benefit)	$ 0.3	$ 2.2	$ (2.4)

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Operating Activities

Net Income

$ 174.1

$ 172.2

$ 155.8

AFUDC – Equity

(1.2)

(2.1)

Income from Equity Investments – Net of Dividends

(2.3)

(3.2)

(5.7)

Impairment of Goodwill

^[1]

0.0

3.3

Change in Fair Value of Contingent Consideration

^[2]

(2.0)

(0.7)

(13.6)

Deferred Fuel Adjustment Clause Charge

0.0

19.5

0.0

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

1.0

0.4

(6.0)

Depreciation Expense

200.1

171.9

190.6

Amortization of PSAs

(23.6)

(22.3)

Amortization of Other Intangible Assets and Other Assets

10.4

10.2

10.3

Deferred Income Tax Expense (Benefit)

(15.8)

14.4

19.4

Share-Based and ESOP Compensation Expense

6.8

6.6

5.1

Defined Benefit Pension and Other Postretirement Benefit Expense

8.6

10.1

4.6

Bad Debt Expense

1.1

0.8

4.1

Provision for Interim Rate Refund

16.3

32.3

0.0

Provision for Tax Reform Refund

10.7

0.0

Changes in Operating Assets and Liabilities

Accounts Receivable

(10.7)

(8.0)

(4.7)

Inventories

55.5

11.9

13.3

Prepayments and Other

(4.0)

(5.3)

(6.9)

Accounts Payable

13.6

(7.5)

6.5

Other Current Liabilities

6.7

1.8

(10.9)

Cash Contributions to Defined Benefit Pension Plans

(15.0)

(1.7)

(6.3)

Changes in Regulatory and Other Non-Current Assets

6.7

33.7

(10.7)

Changes in Regulatory and Other Non-Current Liabilities

(3.9)

(31.7)

11.1

Cash from Operating Activities

433.1

402.9

334.9

Investing Activities

Proceeds from Sale of Available-for-sale Securities

10.2

10.1

9.0

Payments for Purchase of Available-for-sale Securities

(13.3)

(8.6)

(9.4)

Acquisitions of Subsidiaries – Net of Cash and Restricted Cash Acquired

0.0

(18.5)

(5.8)

Equity Investments

(39.2)

(7.8)

(5.4)

Additions to Property, Plant and Equipment

(312.4)

(208.5)

(265.6)

Other Investing Activities

5.7

4.3

5.1

Cash for Investing Activities

(349.0)

(229.0)

(272.1)

Financing Activities

Proceeds from Issuance of Common Stock

20.3

86.0

30.9

Proceeds from Issuance of Long-Term Debt

75.6

131.5

4.8

Repayments of Long-Term Debt

(95.5)

(189.6)

(57.7)

Acquisition of Non-Controlling Interest

0.0

(8.0)

0.0

(19.7)

(0.9)

Dividends on Common Stock

(115.0)

(108.7)

(102.7)

Other Financing Activities

(0.6)

(1.6)

Cash for Financing Activities

(115.2)

(102.1)

(135.2)

Change in Cash, Cash Equivalents and Restricted Cash

(31.1)

71.8

(72.4)

Cash, Cash Equivalents and Restricted Cash

$ 79.0

$ 110.1

$ 38.3

[1]	See Goodwill and Intangible Assets.
[2]	See Note 9. Fair Value.

Consolidated Statement of Equity - USD ($) $ in Millions	Total	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Common Stock [Member]	Non-Controlling Interest in Subsidiaries [Member]
Beginning Balance at Dec. 31, 2015	$ 1,822.4	$ 573.3	$ (24.5)	$ 1,271.4	$ 2.2
Comprehensive Income
Net Income	155.8	155.3			0.5
Other Comprehensive Income – Net of Taxes
Unrealized Gain (Loss) on Securities	(0.2)		(0.2)
Defined Benefit Pension and Other Postretirement Plans	(3.5)		(3.5)
Total Comprehensive Income	152.1
Common Stock Issued	35.9			35.9
Common Stock Retired	(8.0)			(8.0)
Dividends Declared	(102.7)	(102.7)
Acquisition of Non-Controlling Interest	(6.7)			4.0	(2.7)
Ending Balance at Dec. 31, 2016	1,893.0	625.9	(28.2)	1,295.3	0.0
Comprehensive Income
Net Income	172.2	172.2			0.0
Other Comprehensive Income – Net of Taxes
Unrealized Gain (Loss) on Securities	0.9		0.9
Defined Benefit Pension and Other Postretirement Plans	4.7		4.7
Total Comprehensive Income	177.8
Common Stock Issued	106.1			106.1
Dividends Declared	(108.7)	(108.7)
Ending Balance at Dec. 31, 2017	2,068.2	689.4	(22.6)	1,401.4	0.0
Consolidated Statement of Equity [Roll Forward]
Adjustments to Opening Balance – Net of Income Taxes (a)	0.5	6.1	(5.6)	0.0	0.0
Beginning Balance - Adjusted	2,068.7	695.5	(28.2)	1,401.4	0.0
Comprehensive Income
Net Income	174.1	174.1			0.0
Other Comprehensive Income – Net of Taxes
Unrealized Gain (Loss) on Securities	(0.1)		(0.1)
Defined Benefit Pension and Other Postretirement Plans	1.0		1.0
Total Comprehensive Income	175.0
Common Stock Issued	27.1			27.1
Dividends Declared	(115.0)	(115.0)
Ending Balance at Dec. 31, 2018	$ 2,155.8	$ 754.6	$ (27.3)	$ 1,428.5	$ 0.0

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

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.

On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million, subject to adjustment at closing, such as for changes in working capital. The transaction is expected to close by the end of the first quarter of 2019 upon receipt of regulatory approval. The Company expects to recognize a gain on the sale of U.S. Water Services estimated at approximately $10 million after-tax.

Principles of Consolidation. Our Consolidated Financial Statements include the accounts of ALLETE and all of our majority‑owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

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

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

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

Corporate and 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 2018, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 11. Commitments, Guarantees and Contingencies.)

ALLETE Properties represents our legacy Florida real estate investment. Our strategy incorporates the possibility of a bulk sale of the entire ALLETE Properties portfolio. Proceeds from a bulk sale would be strategically deployed to support growth at our Regulated Operations and ALLETE Clean Energy. ALLETE Properties continues to pursue sales of individual parcels over time and will continue to maintain key entitlements and infrastructure. (See Note 8. Investments.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. Restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement and 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 and PSAs, and 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 amount presented in the Consolidated Statement of Cash Flows. During the first quarter of 2018, the Company updated the presentation of its Consolidated Statement of Cash Flows to include restricted cash with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. (See Recently Adopted Pronouncements - Statement of Cash Flows: Restricted Cash.)



Cash, Cash Equivalents and Restricted Cash	December 31, 2018		December 31, 2017		December 31, 2016
Millions
Cash and Cash Equivalents		$69.1		$98.9		$27.5
Restricted Cash included in Prepayments and Other	1.3		2.6		2.2
Restricted Cash included in Other Non-Current Assets	8.6		8.6		8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		$79.0		$110.1		$38.3

Supplemental Statement of Cash Flow Information.



Consolidated Statement of Cash Flows
Year Ended December 31	2018		2017		2016
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$66.0		$64.5		$68.2
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	$(0.1)		$67.2		$(22.0)
Reclassification of Property, Plant and Equipment to Inventory (a)		$46.3	—		—
Capitalized Asset Retirement Costs	$14.2		$(15.6)		$3.7
Camp Ripley Solar Financing	—		—			$15.0
AFUDC–Equity		$1.2		$1.2		$2.1
ALLETE Common Stock Contributed to Pension Plans	—			$13.5	—
ALLETE Common Stock Received for Land Inventory	—		—			$8.0
Long-Term Finance Receivable for Land Inventory	—		—			$12.0

(a)

On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a $46.3 million 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable (Continued)



Accounts Receivable
As of December 31	2018		2017
Millions
Trade Accounts Receivable
Billed		$121.7		$112.6
Unbilled	24.4		24.6
Less: Allowance for Doubtful Accounts	1.7		2.1
Total Accounts Receivable		$144.4		$135.1

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 $11.7 million as of December 31, 2018 ($13.8 million as of December 31, 2017). 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 10 percent of consolidated operating revenue in 2018 (10 percent in 2017 and 8 percent in 2016).

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. (See Note 8. Investments.)

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 U.S. Water Services and ALLETE Clean Energy segments, 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	2018			2017
Millions
Fuel (a)		$26.0			$34.8
Materials and Supplies	44.2			46.5
Raw Materials	2.8			2.8
Work in Progress	6.1			4.2
Finished Goods	8.4			8.3
Reserve for Obsolescence	(0.8		)	(0.7		)
Total Inventories – Net		$86.7			$95.9


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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 in our U.S. Water Services segment and 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.

Impairment of Long-Lived Assets. We review our long-lived assets, which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. 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 sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to maintain the operations.

In 2018, 2017, and 2016, our qualitative assessments indicated that the cash flows were adequate to recover the carrying value of ALLETE Properties real estate assets. As a result, no impairment was recorded in 2018, 2017, or 2016.

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 16. Employee Stock and Incentive Plans.)

Goodwill and Intangible Assets.

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Goodwill and Intangible Assets (Continued)

As part of the 2016 annual impairment analysis, the Company recognized a non-cash impairment charge of $3.3 million for ALLETE Clean Energy’s goodwill primarily related to the acquisition of Storm Lake II in 2014. The charge, which is presented within Operating Expenses – Other in the Consolidated Statement of Income, eliminated all recognized goodwill for the ALLETE Clean Energy reporting unit.

As of the date of our annual goodwill impairment testing in 2018, the U.S. Water Services reporting unit had positive equity and the Company elected to bypass the qualitative assessment of goodwill for impairment, proceeding directly to the two-step impairment test. In performing Step 1 of the impairment test, we compared the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the impairment test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

U.S. Water Services. For Step 1 of the impairment test, we estimated the reporting unit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes a growth rate on debt-free cash flows. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. Our annual impairment test in 2018 indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and therefore no impairment existed (none in 2017 or in 2016). The fair value of the reporting unit was determined using a discounted cash flow model, using significant assumptions which included a discount rate of 12.0 percent, cash flow forecasts through 2023, annual revenue growth rates ranging from 6.0 percent to 10.0 percent, and a terminal growth rate of 3.5 percent. Forecasted annual revenue growth assumes an increase in market share and growth in the industry. (See Subsequent Events.)

Intangible Assets. Intangible assets include customer relationships, patents, non-compete agreements, land easements, trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents, non-compete agreements, land easements and certain trade names, which are amortized on a straight-line basis with estimated remaining useful lives ranging from approximately 4 years to approximately 19 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite‑lived intangible assets consist of trademarks and certain trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Fair value is generally determined using a discounted cash flow analysis. Our annual impairment test in 2018 indicated that the estimated fair value of trademarks and trade names exceeded the asset carrying values. As a result, no impairment existed in 2018 (none in 2017 or in 2016).



Other Non-Current Assets
As of December 31	2018		2017
Millions
Contract Assets (a)		$30.7		$31.6
Finance Receivable (b)	10.4		11.0
Other	62.2		65.1
Total Other Non-Current Assets		$103.3		$107.7


(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 reflects the remaining balance due from the ALLETE Properties sale of its Ormond Crossings project and Lake Swamp wetland mitigation bank.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Current Liabilities
As of December 31	2018		2017
Millions
Provision for Interim Rate Refund		$40.0	—
PSAs	12.6			$24.5
Contract Liabilities (a)	7.6		8.7
Provision for Tax Reform Refund	10.7		—
Contingent Consideration (b)	3.8		—
Other	53.8		50.0
Total Other Current Liabilities		$128.5		$83.2


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


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 9. Fair Value.)



Other Non-Current Liabilities
As of December 31	2018		2017
Millions
Asset Retirement Obligation		$138.6		$122.7
PSAs	76.9		89.5
Contingent Consideration (a)	—		5.4
Other	47.1		49.5
Total Other Non-Current Liabilities		$262.6		$267.1


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 9. Fair Value.)

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 11. 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

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 16 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 from 2019 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, iron concentrate, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 50 percent of total regulated utility kWh sales for the year ended December 31, 2018. 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 2022 through 2028. 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 $75 million in 2019, $55 million per annum in 2020 through 2022, $25 million in 2023, and $75 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 $10 million in 2019. 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Alternative Programs includes revenue that is driven by factors outside of our regulated entities’ control or as a result of the achievement of certain objectives, such as 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.

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 2019 through 2032. 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

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.

See Note 17. Business Segments for additional detail of disaggregated revenue by nature of revenue stream.

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, 2018, we have $30.7 million of assets recognized for costs incurred to obtain contracts with our customers ($31.6 million as of December 31, 2017). 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 and $2.7 million of non-cash amortization for the year ended December 31, 2018 and 2017, respectively.



Operating Expenses – Other
Year Ended December 31	2018	2017	2016
Millions
Impairment of Goodwill (a)	—	—		$3.3
Change in Fair Value of Contingent Consideration (b)	$(2.0)	$(0.7)	(13.6		)
Total Operating Expenses – Other	$(2.0)	$(0.7)	$(10.3)


(a)	See Goodwill and Intangible Assets.


(b)	See Note 9. 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.

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 13. Income Tax Expense.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Income Taxes (Continued)

Tax Cuts and Jobs Act of 2017. On December 22, 2017, the TCJA was enacted. Under ASC 740, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provided for up to a one-year period in which to complete the required analysis and accounting for the TCJA. The one-year period is now complete and the final impact was immaterial.

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.

Purchase Accounting. In accordance with authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the Consolidated Balance Sheet if it exceeds the estimated fair value and as a bargain purchase gain on the Consolidated Income Statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts as well as the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. (See Note 6. Acquisitions.)

New Accounting Pronouncements.

Recently Adopted Pronouncements

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. In February 2018, the FASB issued an update allowing for a one-time reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the enactment of the TCJA. With the enactment of the new federal tax rates in 2017, entities were required to adjust deferred income tax assets and liabilities to reflect the lower federal rate. The effect of this reduction impacted income from continuing operations in the period of enactment, even in instances where the related income tax effects of items were originally recognized in other comprehensive income. As such, companies were left with stranded tax effects in accumulated other comprehensive income that did not reflect the appropriate tax rate. This guidance is effective in the first quarter of 2019 with early adoption permitted. The Company elected to early adopt this guidance in the first quarter of 2018, which resulted in a reduction of $5.7 million to Accumulated Other Comprehensive Loss and a corresponding increase to Retained Earnings for the reclassification of the stranded income tax effects.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued an accounting standard update to improve the presentation of net periodic pension and postretirement benefit costs. Under the guidance, an entity is required to present the service cost component of the net periodic benefit cost in the same income statement line as other employee compensation costs arising from services rendered during the period. The guidance also allows only the service cost component of the periodic cost to be eligible for capitalization on a prospective basis. The other components of net periodic expense must be presented separately from the line item that includes the service cost and must be excluded from the operating income subtotal. The Company adopted the guidance in the first quarter of 2018 and retrospectively adjusted the presentation of the service cost component and the other components of net periodic costs in the Consolidated Statement of Income. The retrospective adjustments for the years ended December 31, 2017, and 2016, were as follows: Operating and Maintenance increased $4.2 million and $6.8 million, respectively, and Cost of Sales – Non-utility decreased $0.3 million in each year, resulting in an increase of $3.9 million and $6.5 million, respectively, to Other Income (Expense) – Other. There was no impact to net income as a result of adoption.

Financial Instruments. In 2016, the FASB issued an accounting standard update which requires entities to measure equity investments at fair value and recognize any changes in fair value in net income unless the investments qualify for the practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The update was adopted by the Company in the first quarter of 2018 which resulted in a cumulative-effect transition adjustment reducing Retained Earnings by $0.1 million, including the tax effect, for the previously unrealized loss on available-for-sale equity securities in Accumulated Other Comprehensive Loss as of December 31, 2017.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Classification of Certain Cash Receipts and Cash Payments. In 2016, the FASB issued an accounting standard update which addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero‑coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments of this update were adopted by the Company in the first quarter of 2018. The adoption of this standard update resulted in an increase to Cash from Operating Activities of $2.9 million and a decrease to Cash for Financing Activities of a corresponding amount for the year ending December 31, 2016, due to the reclassification of debt extinguishment costs incurred by ALLETE Clean Energy in 2016.

Statement of Cash Flows: Restricted Cash. In 2016, the FASB issued an accounting standard update related to the presentation of restricted cash in the Company’s Consolidated Statement of Cash Flows. The update requires that the Consolidated Statement of Cash Flows explain the change during the period in cash, cash equivalents and restricted cash. Restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. This standard update was adopted by the Company in the first quarter of 2018 and was applied retrospectively to the periods presented in the Consolidated Statement of Cash Flows, which resulted in a net decrease for Cash for Financing Activities of $0.4 million and $0.7 million for the years ended December 31, 2017 and 2016, respectively, and a decrease in Cash for Investing Activities of $4.1 million for the year ended December 31, 2016. A reconciliation of Cash and Cash Equivalents presented on the Consolidated Balance Sheet to Cash, Cash Equivalents and Restricted Cash presented on the Consolidated Statement of Cash Flows can be found above under Cash, Cash Equivalents and Restricted Cash.

Revenue from Contracts with Customers. In 2014, the FASB issued amended revenue recognition guidance that clarifies the principles for recognizing revenue from contracts with customers by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The guidance requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled to in exchange for those goods or services. The guidance requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures regarding customer contracts, significant judgments and changes in those judgments, and the assets recognized from the costs to obtain or fulfill a contract are required. The Company adopted this accounting guidance in the first quarter of 2018 and elected to apply the modified retrospective method of adoption to all contracts as of the date of initial application. The financial impact to the consolidated financial statements as a result of adoption of the new standard is immaterial. Based on the nature of the contracts with our customers and our related performance obligations which transfer control, a $0.5 million after-tax cumulative‑effect transition adjustment was made to increase the opening balance of Retained Earnings. We have included additional disclosures in the notes to the consolidated financial statements including additional information on the Company’s revenue streams and related performance obligations required to be satisfied in order to recognize revenue. (See Revenue Recognition.)

Practical Expedients

The following practical expedients were used by the Company as part of the adoption of the new revenue recognition guidance:


•	We have a right to consideration from our customers in an amount that corresponds directly with the value to such customer for performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.


•	We do not adjust the promised amount of consideration for the effects of a significant financing component as at contract inception we expect that the period between when we transfer a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Where applicable, we adopted this guidance using the portfolio approach in which contracts that have similar characteristics were reviewed as a portfolio. The effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying the guidance to each individual contract.


•	We recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that would otherwise have been recognized is one year or less.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Pronouncements

Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued updated guidance which simplifies the measurement of goodwill impairment by removing step two of the goodwill impairment test that requires the determination of the fair value of individual assets and liabilities of a reporting unit. The updated guidance requires goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis.

Leases. In 2016, the FASB issued an accounting standard update which revises the existing guidance for leases. Under the revised guidance, lessees will be required to recognize a “right-of-use” asset and a lease liability for all leases with a term greater than 12 months. The new standard also requires additional quantitative and qualitative 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 are not expected to significantly change as a result of the new guidance. As of December 31, 2018, the Company has reviewed all of its leases, completing our evaluation of the impact of this guidance. At adoption, we expect to recognize right-of-use assets and lease liabilities of approximately $36 million, which represents the discounted future minimum operating lease payments. The Company will adopt and implement the new guidance utilizing the additional optional transition method and package of practical expedients in the period of adoption without retrospective adjustment. Management continues to finalize additional qualitative and quantitative disclosures to meet the requirements of the new standard following adoption. The revised guidance is effective for the Company beginning in the first quarter of 2019.

Reclassification of Prior Income Statement. Beginning with the first quarter of 2018, the Company enhanced its presentation of Operating Revenue on the Consolidated Statement of Income by presenting the caption Operating Revenue separately as Contracts with Customers – Utility, Contracts with Customers – Non-utility, and Other – Non-utility. In conformity with the current presentation, we now present $1,063.8 million and $1,000.7 million of Operating Revenue as Contracts with Customers – Utility for the years ended December 31, 2017, and 2016, respectively, as it is generated from our regulated utility operations. Non-utility revenue of $331.9 million and $316.7 million as well as $23.6 million and $22.3 million for the years ended December 31, 2017, and 2016 respectively, is now presented as Contracts with Customers – Non-utility and Other – Non-utility, respectively.

Consolidated Statement of Income. In 2018, we recognized a $4.4 million reduction in revenue for MISO rates that were billed in 2017 and are expected to be credited to customers in 2019. We have evaluated the effect of this out-of-period adjustment on the years ended December 31, 2018, and 2017, and concluded that this adjustment is not material to any of the periods affected.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2018			2017
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,490.6			$4,523.7
Construction Work in Progress	251.1			121.6
Accumulated Depreciation	(1,549.6		)	(1,520.5		)
Regulated Operations – Net	3,192.1			3,124.8
ALLETE Clean Energy
Property, Plant and Equipment in Service	488.4			482.5
Construction Work in Progress	164.5			144.9
Accumulated Depreciation	(73.0		)	(60.8		)
ALLETE Clean Energy – Net	579.9			566.6
U.S. Water Services
Property, Plant and Equipment in Service	30.1			24.8
Accumulated Depreciation	(14.0		)	(10.4		)
U.S. Water Services – Net	16.1			14.4
Corporate and Other (a)
Property, Plant and Equipment in Service	214.3			204.7
Construction Work in Progress	6.6			5.0
Accumulated Depreciation	(104.6		)	(93.1		)
Corporate and Other – Net	116.3			116.6
Property, Plant and Equipment – Net		$3,904.4			$3,822.4


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

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



Estimated Useful Lives of Property, Plant and Equipment (Years)
Regulated Operations		ALLETE Clean Energy	5 to 35
Generation	5 to 50	U.S. Water Services	5 to 39
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, 2016		$136.6
Accretion	7.6
Liabilities Settled	(5.9		)
Revisions in Estimated Cash Flows	(15.6		)
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

Jointly-Owned Facilities and Projects

12 Months Ended

Dec. 31, 2018

Jointly-Owned Facilities and Projects [Abstract]

Jointly-Owned Facilities and Projects [Text Block]

JOINTLY-OWNED FACILITIES AND ASSETS

Boswell Unit 4. Minnesota Power owns 80 percent of the 585 MW Boswell Unit 4. While Minnesota Power operates the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which it and WPPI Energy, the owner of the remaining 20 percent, have equal representation and voting rights. Each owner must provide its own financing and is obligated to its ownership share of operating costs. Minnesota Power’s share of operating expenses for Boswell Unit 4 is included in Operating Expenses on the Consolidated Statement of Income.

CapX2020. Minnesota Power was a participant in the CapX2020 initiative which represented an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consisted of electric cooperatives and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, assessed the transmission system and projected growth in customer demand for electricity through 2020. Minnesota Power participated in certain CapX2020 projects which were completed and placed in service by 2015.

Minnesota Power’s investments in jointly-owned facilities and projects and the related ownership percentages are as follows:



Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
As of December 31, 2018
Boswell Unit 4		$650.1		$229.9		$6.4	80
CapX2020	101.0		11.0		—		9.3 - 14.7
Total		$751.1		$240.9		$6.4
As of December 31, 2017
Boswell Unit 4		$668.2		$222.8		$8.2	80
CapX2020	101.0		8.4		—		9.3 - 14.7
Total		$769.2		$231.2		$8.2

Regulatory Matters

12 Months Ended

Dec. 31, 2018

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 $103.8 million in 2018 ($96.9 million in 2017; $97.1 million in 2016). 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.)

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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

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

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

FERC-Approved Wholesale Rates. Minnesota Power has 16 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 contracts with SWL&P and another municipal customer are effective through at least February 28, 2022, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided termination notice for its contract in 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. The rates included in these three 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 include fixed capacity charges through 2018; beginning in 2019, the capacity charge will be 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 will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates which allows 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. As a result of the MPUC approval of the certificate of need for the GNTL in 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission bill factor filings.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated November 19, 2018.

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.

In a November 2016 order, the MPUC directed Minnesota Power to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in Operating Revenue of $15.0 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income in 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC.

In a December 2017 order, the MPUC modified its November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in Operating Revenue of $14.0 million in 2017. The North Dakota investment tax credits previously recorded were reestablished as income tax credits in Corporate and Other, resulting in a $7.9 million increase to net income in 2017.

The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in Corporate and Other operations.

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 an order dated November 19, 2018.

Fuel Adjustment Clause Reform. In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order will change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forwarded-looking FAC with an annual prudence review and true-up to actual allowed costs. The MPUC is seeking input from Minnesota electric utilities and other stakeholders on the implementation and transition accounting needed to adopt the change. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of the forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. In an order dated December 12, 2018, the MPUC deferred the implementation date to January 1, 2020.

Tax Cuts and Jobs Act of 2017. In December 2017, the MPUC opened a docket to review the effects of the TCJA on electric and natural gas rates and services in Minnesota, including the legislation’s impact on tax rates and utilities’ deferred income tax assets and liabilities. On March 2, 2018, Minnesota Power submitted an initial filing to the MPUC regarding the impacts of the TCJA on Minnesota Power. As part of Minnesota Power’s rate case, in an order dated May 29, 2018, the MPUC directed Minnesota Power to utilize the benefits of the lower federal income tax rate enacted as part of the TCJA to offset an increase in depreciation expense, effective January 1, 2018, resulting from the reduction in the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 that would have otherwise resulted in an increase in customer rates. The impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities was not addressed in the rate case order.

In an order dated December 5, 2018, the MPUC determined the regulatory treatment for the impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities. The MPUC authorized Minnesota Power to amortize the income tax benefits from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA primarily over the life of the related property, plant and equipment with the remainder amortized over a 10-year period. The MPUC directed Minnesota Power to return these excess deferred income tax benefits as a monthly bill credit beginning with the implementation of final rates on December 1, 2018. Additionally, Minnesota Power customers will receive a one-time bill credit in 2019 for the benefit of the excess deferred income taxes from January 1, 2018, through November 30, 2018.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

On January 10, 2018, the PSCW opened a docket to review the effects of the TCJA and directed Wisconsin utilities to defer its impacts until further direction was provided by the PSCW. In an order dated May 24, 2018, the PSCW directed SWL&P to refund the benefits of the lower federal income tax rates enacted as part of the TCJA on customer bills beginning in July 2018. In an order dated December 20, 2018, the PSCW directed SWL&P to return the excess deferred income tax benefits for 2018 in 2019 and 2020, and include the return of excess deferred income tax benefits going forward in final rates effective January 1, 2019, with a true-up in its next rate case. (See 2018 Wisconsin General Rate Case.) These excess deferred income tax benefits for SWL&P will be returned primarily over the life of the related property, plant and equipment with the remainder amortized over a 4-year period.

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

2018 Wisconsin General Rate Case. On May 25, 2018, SWL&P filed a rate increase request with the PSCW requesting an average increase of 2.7 percent for retail customers (2.0 percent increase in electric rates; 2.3 percent increase in natural gas rates; and 8.3 percent increase in water rates). The filing sought an overall return on equity of 10.5 percent and a 55.41 percent equity ratio. In an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return on equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of approximately $1.3 million on an annualized basis.

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

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

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

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

NOTE 4. REGULATORY MATTERS (Continued)

Great Northern Transmission Line (Continued)

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

Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Transmission Cost Recovery Rider.) Minnesota Power also has FERC approval to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers.

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 November 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 $10.3 million for 2018 ($10.3 million for 2017; $7.3 million for 2016), with actual spending of $9.0 million in 2018 ($8.1 million in 2017; $7.4 million in 2016). The investment goal for 2019 is $10.5 million.

On April 2, 2018, Minnesota Power submitted its 2017 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $3.0 million based on MPUC procedures. In an order dated September 4, 2018, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive which was recorded as revenue and as a regulatory asset in 2018. The approved financial incentive will be recovered in customer billing rates in 2018 and 2019. In 2017 and 2016, the CIP financial incentives recognize were $5.5 million and $7.5 million, respectively. 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 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization.

In 2016, a federal administrative law judge ruled on a complaint proposing a reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending, which is not expected to have a material impact on our Consolidated Financial Statements.

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. In an order dated October 2, 2018, the MPUC approved a PPA for the output of the 10 MW Blanchard solar energy facility to be located in central Minnesota. Minnesota Power expects that Camp Ripley, the community solar garden arrays, the PPA for the output of the 10 MW Blanchard solar energy facility, and an increase in solar rebates will allow Minnesota Power to meet both parts of the solar mandate.

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, 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	2018		2017
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)		$218.5		$220.3
Income Taxes (c)	105.5		112.8
Asset Retirement Obligations (d)	32.6		29.6
Boswell 1 & 2 (l)	16.3		—
Manufactured Gas Plant (e)	8.0		8.1
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program (f)	—		3.3
Other	3.6		5.6
Total Non-Current Regulatory Assets		$389.5		$384.7
Current Regulatory Liabilities (a)
Provision for Interim Rate Refund (i)		$40.0	—
Provision for Tax Reform Refund (j)	10.7		—
Transmission Formula Rates	4.4		—
Total Current Regulatory Liabilities	55.1		—
Non-Current Regulatory Liabilities
Income Taxes (c)	396.4			$411.2
Wholesale and Retail Contra AFUDC (h)	64.4		57.9
Provision for Interim Rate Refund (i)	—		23.7
Plant Removal Obligations	25.1		20.3
North Dakota Investment Tax Credits (k)	14.7		14.1
Cost Recovery Riders (g)	6.9		2.2
Transmission Formula Rates	1.6		—
Other	3.0		2.6
Total Non-Current Regulatory Liabilities	512.1		532.0
Total Regulatory Liabilities		$567.2		$532.0


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

(b)

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 15. Pension and Other Postretirement Benefit Plans.)


(c)	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 and flow through current income taxes.


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


(e)	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.


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


(g)	The cost recovery rider regulatory liabilities are cash collections from our customers in excess of revenue recognized, 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 liabilities as of December 31, 2018, will be returned within the next two years.


(h)	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.


(i)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in 2019 and includes $23.8 million of discounts provided to EITE customers as of December 31, 2018, that will be offset against interim rate refunds ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(j)	Provision for tax reform refund is expected to be refunded to Minnesota Power customers in the first quarter of 2019 and SWL&P customers in 2019 and 2020. (See Tax Cuts and Jobs Act of 2017.)


(k)	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.


(l)	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.

Equity Investments

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Investments [Text Block]

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. As of December 31, 2018, our equity investment in ATC was $128.1 million ($118.7 million as of December 31, 2017). On January 31, 2019, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $8.5 million in 2019.



ALLETE’s Investment in ATC
Year Ended December 31	2018			2017
Millions
Equity Investment Beginning Balance		$118.7			$135.6
Cash Investments	6.2			7.8
Equity in ATC Earnings	17.5			22.5
Distributed ATC Earnings	(15.2		)	(19.3		)
Remeasurement of Deferred Income Taxes (a)	—			(27.9		)
Amortization of the Remeasurement of Deferred Income Taxes	0.9			—
Equity Investment Ending Balance		$128.1			$118.7


(a)	Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2018		2017
Millions
Current Assets		$87.2		$87.7
Non-Current Assets	4,928.8		4,598.9
Total Assets		$5,016.0		$4,686.6
Current Liabilities		$640.0		$767.2
Long-Term Debt	2,014.0		1,790.6
Other Non-Current Liabilities	295.3		240.3
Members’ Equity	2,066.7		1,888.5
Total Liabilities and Members’ Equity		$5,016.0		$4,686.6



Income Statement Data
Year Ended December 31	2018		2017		2016
Millions
Revenue		$690.5		$721.6		$650.8
Operating Expense	358.7		344.9		322.5
Other Expense	108.3		104.1		95.5
Net Income		$223.5		$272.6		$232.8
ALLETE’s Equity in Net Income		$17.5		$22.5		$18.5

ATC’s authorized return on equity is 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization.

NOTE 5. EQUITY INVESTMENTS (Continued)

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

Acquisitions

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

The following acquisitions are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. The pro forma impact of the following acquisitions was not significant, either individually or in the aggregate, to the results of the Company for the years ended December 31, 2018, 2017 and 2016.

2017 Activity.

Tonka Water. In September 2017, U.S. Water Services acquired 100 percent of Tonka Water. Total consideration for the transaction was $19.2 million, including a working capital adjustment. Consideration of $19.0 million was paid in cash on the acquisition date and a working capital adjustment of $0.2 million was paid in the fourth quarter of 2017. Tonka Water is a supplier of municipal and industrial water treatment systems that expanded U.S. Water Services’ geographic and customer markets.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2018, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.



Millions
Assets Acquired
Accounts Receivable	$5.1
Other Current Assets	5.1
Trade Names (a)	0.9
Goodwill (a)(b)	16.9
Other Non-Current Assets	0.2
Total Assets Acquired		$28.2
Liabilities Assumed
Current Liabilities		$9.0
Total Liabilities Assumed		$9.0
Net Identifiable Assets Acquired		$19.2

(a) Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)


(b)	Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill.

Acquisition-related costs were immaterial, expensed as incurred during 2017 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

2016 Activity.

Acquisition of Non-Controlling Interest. In 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns its Condon wind energy facility for $8.0 million. This transaction was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income. As a result of the acquisition, the Condon wind energy facility is now a wholly-owned subsidiary of ALLETE Clean Energy.

NOTE 6. ACQUISITIONS (Continued)

2016 Activity (Continued)

WEST. In 2016, U.S. Water Services acquired 100 percent of Water & Energy Systems Technology of Nevada, Inc. (WEST). Total consideration for the transaction was $6.7 million. Consideration of $5.9 million was paid in cash on the acquisition date, working capital adjustments of $0.2 million were paid in 2017 and a $0.6 million payment was made in April 2018. WEST is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southwestern United States.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2017, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.



Millions
Assets Acquired
Cash and Cash Equivalents		$0.1
Other Current Assets	1.0
Customer Relationships (a)	2.8
Goodwill (a)(b)	4.2
Other Non-Current Assets	0.1
Total Assets Acquired		$8.2
Liabilities Assumed
Current Liabilities		$0.3
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.5
Net Identifiable Assets Acquired		$6.7


(a)	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisition-related costs were immaterial, expensed as incurred during 2016 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The following table summarizes changes to goodwill by reportable segment:



	U.S. Water Services
Millions
Balance as of December 31, 2016		$131.2
Acquired Goodwill (a)	16.9
Other Adjustments (b)	0.2
Balance as of December 31, 2017	148.3
Other Adjustments (b)	0.2
Balance as of December 31, 2018		$148.5


(a)	See Note 6. Acquisitions.


(b)	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 and acquisition of Tonka Water was completed in 2018 resulting in adjustments in those periods to the goodwill recorded at the time of acquisition.

NOTE 7. GOODWILL AND INTANGIBLE ASSETS (Continued)

The following table summarizes changes to intangible assets, net, for the year ended December 31, 2018:



	December 31, 2017		Additions		Amortization	December 31, 2018
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$54.7		$0.2	$(4.2)		$50.7
Developed Technology and Other (a)	6.3		2.6		(1.4)	7.5
Total Definite-Lived Intangible Assets	61.0		2.8		(5.6)	58.2
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$77.6		$2.8	$(5.6)		$74.8


(a)	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

Customer relationships have a remaining useful life of approximately 19 years, and developed technology and other have remaining useful lives ranging from approximately 4 years to approximately 10 years (weighted average of approximately 6 years). The weighted average remaining useful life of all definite-lived intangible assets as of December 31, 2018, is approximately 17 years.

Amortization expense of intangible assets for the year ended December 31, 2018, was $5.6 million ($5.5 million in 2017; $5.2 million in 2016). Accumulated amortization was $20.4 million and $14.8 million as of December 31, 2018, and December 31, 2017, respectively. Estimated amortization expense for definite-lived intangible assets is $5.3 million in 2019, $4.9 million in 2020, $4.9 million in 2021, $4.6 million in 2022, $4.3 million in 2023 and $34.2 million thereafter.

Fair Value

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value [Text Block]

FAIR VALUE

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

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

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

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes 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, 2018, and December 31, 2017. 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, 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:
Deferred Compensation (b)	—			$19.8	—			$19.8
U.S. Water Services Contingent Consideration (c)	—		—			$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 Investments on the Consolidated Balance Sheet.


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


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

NOTE 9. FAIR VALUE (Continued)



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$10.2	—		—			$10.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.9	—		8.9
Cash Equivalents	3.8		—		—		3.8
Total Fair Value of Assets		$14.0		$8.9	—			$22.9

Liabilities: (b)
Deferred Compensation	—			$18.2	—			$18.2
U.S. Water Services Contingent Consideration	—		—			$5.4	5.4
Total Fair Value of Liabilities	—			$18.2		$5.4		$23.6
Total Net Fair Value of Assets (Liabilities)		$14.0	$(9.3)		$(5.4)		$(0.7)


(a)	Included in Other Investments on the Consolidated Balance Sheet.


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

The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of December 31, 2018, and December 31, 2017. The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value was measured based on the consideration expected to be transferred, discounted to present value. The discount rate was determined at the time of measurement in accordance with generally accepted valuation methods. The fair value of the acquisition contingent consideration is remeasured to arrive at estimated fair value each reporting period with the change in fair value recognized as income or expense in the Consolidated Statement of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, timing of milestones that trigger payments, and the timing and amount of earnings estimates. Using different valuation assumptions, including earnings projections or discount rates, may result in different fair value measurements and expense (or income) in future periods. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate. The acquisition contingent consideration was measured at $3.8 million as of December 31, 2018.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2016		$25.0
Accretion (a)	0.8
Payments (b)	(19.7		)
Changes in Cash Flow Projections	(0.7		)
Balance as of December 31, 2017		$5.4
Accretion (a)	0.4
Changes in Cash Flow Projections	(2.0		)
Balance as of December 31, 2018		$3.8


(a)	Included in Interest Expense on the Consolidated Statement of Income.


(b)	Payments reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, and were paid in 2017.

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, 2018 and 2017, there were no transfers in or out of Levels 1, 2 or 3.

NOTE 9. FAIR VALUE (Continued)

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, 2018	$1,495.2	$1,534.6
December 31, 2017	$1,513.3	$1,627.6

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 $161.1 million as of December 31, 2018 ($118.7 million as of December 31, 2017). 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, 2018 and 2017, there were no indicators of impairment. (See Note 5. Equity Investments.)

Goodwill. The Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. The Company’s goodwill is a result of the U.S. Water Services acquisition in 2015 as well as U.S. Water Services’ subsequent acquisitions. (See Note 6. Acquisitions.) The aggregate carrying amount of goodwill was $148.5 million as of December 31, 2018, and $148.3 million as of December 31, 2017.

Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The inputs used in the fair value analysis fall within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs to determine fair value. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. The Company calculates the excess of the reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. Our annual impairment test for U.S. Water Services indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and no impairment existed for the year ended December 31, 2018 (none in 2017 and none in 2016). As part of the 2016 annual impairment analysis, the Company recognized a non-cash impairment charge of $3.3 million for ALLETE Clean Energy’s goodwill primarily related to the acquisition of Storm Lake II in 2014. The charge, which is presented within Operating Expenses – Other in the Consolidated Statement of Income, eliminated all goodwill for the ALLETE Clean Energy reporting unit. (See Note 1. Operations and Significant Accounting Policies.)

Intangible Assets. The Company assesses indefinite-lived intangible assets for impairment annually in the fourth quarter. The Company also assesses indefinite-lived and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable. Substantially all of the Company’s intangible assets are a result of the U.S. Water Services acquisition in 2015 as well as U.S. Water Services’ subsequent acquisitions. The aggregate carrying amount of intangible assets was $74.8 million as of December 31, 2018 ($77.6 million as of December 31, 2017). When events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable, the Company calculates the excess of an intangible asset's carrying amount over its undiscounted future cash flows. If the carrying amount is not recoverable, an impairment loss is recorded based on the amount by which the carrying amount exceeds the fair value. The inputs used in the fair value analysis fall within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs to determine fair value. As of December 31, 2018, there have been no events or changes in circumstance which would indicate impairment of our intangible assets.

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. The impairment of ALLETE Clean Energy’s goodwill in 2016, primarily due to lower estimated energy prices in periods not under PSAs, caused management to review ALLETE Clean Energy’s WTGs for impairment. Based on the results of the undiscounted cash flow analysis, the undiscounted future cash flows were adequate to recover the carrying value of the WTGs. (See Note 1. Operations and Significant Accounting Policies.) For the years ended December 31, 2018, and 2017, there was no impairment of property, plant, and equipment.

NOTE 9. 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, 2018

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2018, total short-term debt outstanding was $57.5 million ($64.1 million as of December 31, 2017), consisted of long-term debt due within one year and included $0.4 million of unamortized debt issuance costs.

As of December 31, 2018, we had consolidated bank lines of credit aggregating $407.0 million ($407.0 million as of December 31, 2017), most of which expire in January 2024. We had $18.4 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of December 31, 2018 ($11.9 million in standby letters of credit and no outstanding draws as of December 31, 2017).

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 $60 million in letters of credit.

Long-Term Debt. As of December 31, 2018, total long-term debt outstanding was $1,428.5 million ($1,439.2 million as of December 31, 2017) and included $8.8 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2019 is $57.9 million; $113.7 million in 2020; $98.5 million in 2021; $89.3 million in 2022; $88.5 million in 2023; and $1,047.3 million thereafter. Substantially all of our regulated electric plant is subject to the lien of the mortgages collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

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

On April 16, 2018, ALLETE issued and sold $60.0 million of its First Mortgage Bonds (the Bonds) that bear interest at 4.07 percent. The Bonds will mature in April 2048 and pay interest semi-annually in April and October of each year, commencing on October 16, 2018. 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 intends to use 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 10. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt (Continued)

On October 3, 2018, and October 17, 2018, ALLETE repaid $20.0 million and $10.0 million, respectively, under an unsecured term loan due in 2020.



Long-Term Debt
As of December 31	2018			2017
Millions
First Mortgage Bonds
1.83% Series Due 2018	—				$50.0
8.17% Series Due 2019		$42.0		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
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			—
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Unsecured Term Loan Variable Rate Due 2020	10.0			40.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024	57.2			65.9
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			—
Other Long-Term Debt, 3.11% – 5.75% Due 2019 – 2037	67.7			69.1
Unamortized Debt Issuance Costs	(9.2		)	(10.0		)
Total Long-Term Debt	1,486.0			1,503.3
Less: Due Within One Year	57.5			64.1
Net Long-Term Debt		$1,428.5			$1,439.2

NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of December 31, 2018, our ratio was approximately 0.41 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, 2018, ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2018

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, 2018
Millions	2019		2020		2021		2022		2023		Thereafter
Coal, Rail and Shipping Contracts		$20.8		$9.0		$7.5	—		—		—
Operating Leases		$9.9		$7.9		$6.1		$4.9		$3.1		$9.4
Easements		$4.8		$4.9		$4.9		$5.0		$5.1		$136.3
Other (a)		$31.6		$0.3		$0.3	—		—			$0.1
PPAs (b)		$107.3		$115.3		$145.4		$145.7		$145.8		$1,550.7


(a)	Consists of long-term service agreements for 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.)

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, 2018, Square Butte had total debt outstanding of $304.0 million. Annual debt service for Square Butte is expected to be approximately $48.7 million in each of the next five years, 2019 through 2023, 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.

Minnesota Power’s cost of power purchased from Square Butte during 2018 was $78.0 million ($75.7 million in 2017; $73.3 million in 2016). 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 $9.1 million in 2018 ($9.4 million in 2017; $9.6 million in 2016). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power has also entered into the following PPAs for the purchase or sale of capacity and energy as of December 31, 2018:



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


(a)	The PPA provides for the purchase of all output from the 10 MW Blanchard solar energy facility to be located in central Minnesota. Construction of the Blanchard solar energy facility is expected to be completed in 2020 and the contract is effective for 25 years beginning upon commercial operation.


(b)	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.


(c)	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.


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


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


(f)	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.


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


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


(i)	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.)


(j)	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.


(k)	Minnesota Power is purchasing 50 MW of energy during off-peak hours and 100 MW of energy during on-peak hours.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power has also entered into the following PSAs for the purchase or sale of capacity and energy as of December 31, 2018:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(a)
PSA 2	50 MW	Capacity	June 2017	May 2019	Fixed
PSA 3	(b)	Capacity	June 2022	May 2025	Fixed
PSA 4	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 2018 (28 percent in 2017 and in 2016). (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. Through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power has the option to purchase additional energy. By December 31, 2019, Silver Bay Power is expected to cease self-generation and Minnesota Power is expected to supply the energy requirements for Silver Bay Power.


(e)	The energy pricing is 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 2019 and a 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.

Leasing Agreements. BNI Energy is obligated to make lease payments for a dragline totaling $2.8 million annually during the lease term, which expires in 2027. BNI Energy has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with a majority of terms expiring through 2024. Total lease expense was $14.6 million in 2018 ($17.5 million in 2017; $17.1 million in 2016).

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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

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

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. 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 remains pending. 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. Approval of the Canadian federal cabinet is also required.

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 has indicated that it would need to start construction of the MMTP by June 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. Any significant delays in the MMTP construction schedule may result in Minnesota Power adjusting the GNTL construction schedule and impact the timing of capital expenditures and associated cost recovery under our transmission cost recovery rider.

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 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

New Source Review (NSR). In 2014, Minnesota Power reached a settlement with the EPA and entered into a Consent Decree regarding certain Notices of Violation received in 2008 and 2011 that asserted violations of the NSR requirements of the Clean Air Act, which was approved by the U.S. District Court for the District of Minnesota. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofitting or retiring certain small coal units, and the addition of 200 MW of wind energy. Provisions of the Consent Decree require that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted through existing emission control technology at Boswell. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. Minnesota Power is allowed to recover the remaining net book value for Boswell Units 1 and 2 through 2022. We believe that costs to retire Boswell Units 1 and 2 will be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.

Mercury and Air Toxics Standards (MATS) Rule. Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The final MATS rule addressed such emissions from coal-fired utility units greater than 25 MW and established categories of HAPs, including mercury, trace metals other than mercury, and acid gases. The EPA established emission limits for these categories of HAPs and work practice standards for the remaining categories. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan to position the unit for MATS compliance was completed in 2015. Investments and compliance work previously completed at Boswell Unit 3, including emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to operate on natural gas in 2015 positioned those units for MATS compliance. On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for MATS that determined it is not appropriate and necessary to regulate HAP emissions from power plants under section 112 of the Clean Air Act.

Minnesota Mercury Emissions Reduction Act/Rule. Minnesota Power was required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above (see Mercury and Air Toxics Standards (MATS) Rule) fulfills the requirements of the Minnesota Mercury Emissions Reduction Act.

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.

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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA Regulation of GHG Emissions. In 2014, the EPA announced 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”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation plan and a model rule for emissions trading. In 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In 2016, the U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments and is currently deliberating. If the CPP is upheld at the completion of the appellate process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force.

If upheld, the CPP would establish uniform CO₂ emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO₂ emissions from the power sector. State goals were determined based on CPP source-specific performance emission rates and each state’s mix of power plants. The EPA filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in suspension while the EPA is reviewing the rule. In October 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. In December 2017, an Advanced Notice of Proposed Rulemaking for a CPP replacement rule was published in the Federal Register.

On August 31, 2018, the EPA published the proposed Affordable Clean Energy Rule in the Federal Register, which is intended to replace the CPP with revised emission guidelines that inform the development, submittal, and implementation of State Implementation Plans (SIP) to reduce GHG emissions for existing steam generating units. If a state does not submit a SIP or submits a plan that is unacceptable to the EPA, the EPA would develop a Federal Implementation Plan (FIP). Minnesota Power generating facilities affected by this proposal include Boswell, Laskin, Taconite Harbor and Hibbard.

The proposed Affordable Clean Energy Rule seeks to reduce carbon intensity at existing steam generation units by prescribing Best System of Emission Reduction (BSER), primarily through Heat Rate Improvement (HRI) technologies. Under the proposal, states will have up to three years to develop a SIP, which is subject to EPA approval. While many of the HRIs proposed by the EPA in the proposed rule have already been installed in Minnesota Power’s largest coal-fired generating units, compliance specifics would be detailed in either Minnesota’s SIP or a FIP.

Minnesota has already initiated several measures consistent with those called for under the CPP and proposed Affordable Clean Energy Rule. Minnesota Power is 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 6. Regulatory Matters.) We are unable to predict the GHG emission compliance costs we might incur; 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.

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 September 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.

The final ELG rule’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. Under the existing 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. If FGD wastewater is discharged in the future, it will require additional wastewater treatment. 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 15 years and be between approximately $65 million and $120 million. The EPA has indicated to Minnesota Power that the landfill at Taconite Harbor, which has been idled and has a temporary landfill cover in place, is a CCR unit based on the EPA’s interpretation of the CCR rule language. Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR‑related waters. In September 2017, the EPA announced its intention to formally reconsider 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. On July 17, 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk‑based management options at facilities based on site characteristics. On August 22, 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision changes the status of three existing impoundments at Boswell that must now be considered unlined. Compliance costs at Boswell due to the court decision are unknown at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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 December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of December 31, 2018, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $8 million as of December 31, 2017), 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 2019 and 2032. As of December 31, 2018, ALLETE Clean Energy has $21.0 million outstanding in standby letters of credit.

U.S. Water Services. As of December 31, 2018, U.S. Water Services has no outstanding standby letters of credit.

BNI Energy. As of December 31, 2018, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6 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 $47.5 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

ALLETE Properties. As of December 31, 2018, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $8.6 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $6.1 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, 2018, we owned 68 percent of the assessable land in the Town Center District (70 percent as of December 31, 2017) and 19 percent of the assessable land in the Palm Coast Park District (33 percent as of December 31, 2017). As of December 31, 2018, 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 and $0.6 million for Palm Coast Park. 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.

U.S. Water Services is involved in on-going patent defense litigation it brought against a company for infringement of two patents held by U.S. Water Services. As of December 31, 2018, U.S. Water Services has recognized approximately $2.6 million of patent defense costs as an intangible asset. Management expects that U.S. Water Services will prevail, but in the event of an unfavorable outcome, the patent defense costs would be recognized as an expense in the period of resolution.

Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2018

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, 2015	49,075			$1,271.4
Employee Stock Purchase Plan	16		0.9
Invest Direct	344		20.0
Options and Stock Awards	65		3.7
Contributions to RSOP	60		3.3
Equity Issuance Program	130		8.0
Received for Sale of Land Inventory	(130	)	(8.0		)
Acquisition of Non-Controlling Interest	—		(4.0		)
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
Contribution 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

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, 2018. For the year ended December 31, 2018, no shares of common stock were issued under this agreement (1.0 million shares for net proceeds of $65.7 million in 2017; 0.1 million shares for net proceeds of $8.0 million in 2016). The shares issued in 2017 and 2016 were offered and sold pursuant to Registration Statement No. 333-212794, 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, 2018, we contributed no shares of ALLETE common stock to our pension plan (0.2 million shares, which had an aggregate value of $13.5 million in 2017 and none in 2016). 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 outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. No options to purchase shares of common stock were excluded from the computation of diluted earnings per share in 2018, 2017 and 2016.

NOTE 12. 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
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
Dividends Per Share		$2.24			$2.24
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
Dividends Per Share		$2.14			$2.14
2016
Net Income Attributable to ALLETE		$155.3			$155.3
Average Common Shares	49.3		0.2	49.5
Earnings Per Share		$3.15			$3.14
Dividends Per Share		$2.08			$2.08

Income Tax Expense

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2018			2017			2016
Millions
Current Income Tax Expense (a)
Federal	—			—			—
State	$0.3			$0.3			$0.4
Total Current Income Tax Expense		$0.3			$0.3			$0.4
Deferred Income Tax Expense (Benefit)
Federal (b)	$(26.2)				$12.1			$12.0
Federal – Remeasurement of Deferred Income Taxes (c)	—			(13.0		)	—
State	11.0			15.8			8.1
Investment Tax Credit Amortization	(0.6		)	(0.5		)	(0.7		)
Total Deferred Income Tax Expense (Benefit)	$(15.8)				$14.4			$19.4
Total Income Tax Expense (Benefit)	$(15.5)				$14.7			$19.8

(a)

For the years ended December 31, 2018, 2017 and 2016, 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 year ended December 31, 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 13. INCOME TAX EXPENSE (Continued).



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2018			2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$158.6			$186.9			$175.6
Statutory Federal Income Tax Rate	21		%	35		%	35		%
Income Taxes Computed at Statutory Federal Rate		$33.3			$65.4			$61.5
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	8.9			10.5			5.6
Production Tax Credits	(45.0		)	(45.1		)	(41.5		)
Regulatory Differences – Excess Deferred Tax Benefit (a)	(8.2		)	1.2			1.4
Change in Fair Value of Contingent Consideration	(0.4		)	—			(3.8		)
Remeasurement of Deferred Income Taxes (b)	—			(13.0		)	—
Other	(4.1		)	(4.3		)	(3.4		)
Total Income Tax Expense (Benefit)	$(15.5)				$14.7			$19.8


(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 9.8 percent for 2018 (expense of 7.9 percent for 2017; expense of 11.3 percent for 2016). 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. The 2016 effective tax rate was primarily impacted by production tax credits.



Deferred Income Tax Assets and Liabilities
As of December 31	2018			2017
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation		$62.2			$65.9
Property-Related	95.2			104.3
NOL Carryforwards	86.1			99.1
Tax Credit Carryforwards	349.8			294.3
Power Sales Agreements	27.5			35.0
Regulatory Liabilities	113.4			117.7
Other	25.1			33.3
Gross Deferred Income Tax Assets	759.3			749.6
Deferred Income Tax Asset Valuation Allowance	(66.5		)	(60.0		)
Total Deferred Income Tax Assets		$692.8			$689.6
Deferred Income Tax Liabilities
Property-Related		$752.5			$758.3
Regulatory Asset for Benefit Obligations	61.0			61.4
Unamortized Investment Tax Credits	32.2			32.8
Partnership Basis Differences	40.8			34.9
Regulatory Assets	29.9			32.0
Other	—			0.7
Total Deferred Income Tax Liabilities		$916.4			$920.1
Net Deferred Income Taxes (a)		$223.6			$230.5


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

NOTE 13. INCOME TAX EXPENSE (Continued).



NOL and Tax Credit Carryforwards
As of December 31	2018	2017
Millions
Federal NOL Carryforwards (a)	$319.0		$375.2
Federal Tax Credit Carryforwards	$256.4	$209.2
State NOL Carryforwards (a)	$305.8	$289.9
State Tax Credit Carryforwards (b)	$27.4	$25.6


(a)	Pre-tax amounts.


(b)	Net of a $66.0 million valuation allowance as of December 31, 2018 ($59.5 million as of December 31, 2017).

The federal NOL and tax credit carryforward periods expire between 2031 and 2038. 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, 2018. 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. We do not expect a material impact on the Company’s ability to utilize its federal and state NOL and tax credit carryforwards due to the TCJA.



Gross Unrecognized Income Tax Benefits	2018			2017			2016
Millions
Balance at January 1		$1.7			$2.0			$2.4
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			0.2
Reductions for Tax Positions Related to Prior Years	(0.2		)	(0.1		)	(0.3		)
Lapse of Statute	(0.1		)	(0.4		)	(0.4		)
Balance as of December 31		$1.6			$1.7			$2.0

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, 2018, included $0.9 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2018, we had no accrued interest (none as of December 31, 2017, and 2016) 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 2018 (immaterial in 2017, and in 2016). There were no penalties recognized in 2018, 2017 or 2016. 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 2015 or state examination for years before 2014.

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Text Block]	RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Changes in Accumulated Other Comprehensive Loss. Comprehensive income (loss) is the change in shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale debt securities as well as defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits. For the years ended December 31, 2018, 2017 and 2016, reclassifications out of accumulated other comprehensive loss for the company were not material. Changes in accumulated other comprehensive loss are presented on the Consolidated Statement of Shareholders’ Equity.

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2018

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 $15.0 million in cash to the plans in 2018 ($1.7 million in 2017; $6.3 million in 2016). We contributed no shares of ALLETE common stock to the plans in 2018 (0.2 million shares, which had an aggregate value of $13.5 million in 2017; none in 2016). We also have a defined contribution RSOP covering substantially all employees. The 2018 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $11.4 million ($11.0 million for the 2017 plan year; $9.2 million for the 2016 plan year). (See Note 12. Common Stock and Earnings Per Share and Note 16. 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 2018, no contributions were made to the VEBAs (none in 2017; none in 2016) and no contributions were made to the grantor trusts (none in 2017; none in 2016).

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, 2019, we contributed $10.4 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 2019, and we do not expect to make any contributions to the defined benefit postretirement health and life plans in 2019.

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 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Pension Obligation and Funded Status
As of December 31	2018			2017
Millions
Accumulated Benefit Obligation		$713.7			$745.4
Change in Benefit Obligation
Obligation, Beginning of Year		$793.2			$743.3
Service Cost	11.0			10.2
Interest Cost	29.6			32.5
Plan Amendments	(1.5		)	—
Plan Curtailments	(6.9		)	—
Actuarial (Gain) Loss	(53.0		)	44.8
Benefits Paid	(49.5		)	(51.0		)
Participant Contributions	24.1			13.4
Obligation, End of Year		$747.0			$793.2
Change in Plan Assets
Fair Value, Beginning of Year		$628.2			$557.5
Actual Return on Plan Assets	(21.2		)	91.6
Employer Contribution (a)	40.5			30.1
Benefits Paid	(49.5		)	(51.0		)
Fair Value, End of Year		$598.0			$628.2
Funded Status, End of Year	$(149.0)			$(165.0)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.6)			$(1.4)
Non-Current Liabilities	$(147.4)			$(163.6)


(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 $230.5 million and prior service cost of $1.4 million as of December 31, 2018 (net loss of $236.2 million as of December 31, 2017).



Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2018	2017
Millions
Net Loss	$(230.5)	$(236.2)
Prior Service Cost	1.4	—
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	80.1	71.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(149.0)	$(165.0)

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Components of Net Periodic Pension Cost
Year Ended December 31	2018			2017			2016
Millions
Service Cost		$11.0			$10.2			$8.1
Non-Service Cost Components (a)
Interest Cost	29.6			32.5			33.2
Expected Return on Plan Assets	(44.4		)	(42.4		)	(43.6		)
Amortization of Loss	11.4			9.9			9.5
Amortization of Prior Service Cost	(0.1		)	—			—
Net Pension Cost		$7.5			$10.2			$7.2


(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	2018		2017
Millions
Net (Gain) Loss	$5.8		$(4.3)
Amortization of Prior Service Cost	0.1		—
Prior Service Cost Arising During the Period	(1.6	)	—
Amortization of Loss	(11.4	)	(9.9	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(7.1)		$(14.2)



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2018		2017
Millions
Projected Benefit Obligation		$747.0		$793.2
Accumulated Benefit Obligation		$713.7		$745.4
Fair Value of Plan Assets		$598.0		$628.2

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Postretirement Health and Life Obligation and Funded Status
As of December 31	2018			2017
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$190.1			$173.4
Service Cost	4.7			4.4
Interest Cost	7.1			7.7
Actuarial (Gain) Loss	(15.8		)	15.5
Benefits Paid	(11.6		)	(12.2		)
Participant Contributions	3.6			3.1
Plan Amendments	(2.1		)	(1.8		)
Obligation, End of Year		$176.0			$190.1
Change in Plan Assets
Fair Value, Beginning of Year		$171.0			$154.3
Actual Return on Plan Assets	(9.6		)	24.5
Employer Contribution	1.0			1.3
Participant Contributions	3.6			3.1
Benefits Paid	(11.7		)	(12.2		)
Fair Value, End of Year		$154.3			$171.0
Funded Status, End of Year	$(21.7)			$(19.1)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$0.4			$3.0
Current Liabilities	$(1.0)			$(1.1)
Non-Current Liabilities	$(21.1)			$(21.0)

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 $18.3 million in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of December 31, 2018 ($19.2 million as of December 31, 2017).

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	2018		2017
Millions
Net Loss	$25.0		$21.1
Prior Service Credit	(4.6	)	(4.6	)
Total Unrecognized Postretirement Health and Life Cost	$20.4		$16.5



Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2018		2017
Millions
Net Loss (a)	$(25.0)		$(21.1)
Prior Service Credit	4.6		4.6
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	(1.3	)	(2.6	)
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$(21.7)		$(19.1)


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

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Components of Net Periodic Postretirement Health and Life Cost
Year Ended December 31	2018			2017			2016
Millions
Service Cost		$4.7			$4.4			$3.9
Non-Service Cost Components (a)
Interest Cost	7.1			7.7			7.4
Expected Return on Plan Assets	(10.9		)	(10.5		)	(11.2		)
Amortization of Loss	0.8			0.3			0.2
Amortization of Prior Service Credit	(2.1		)	(2.0		)	(2.9		)
Net Postretirement Health and Life Credit	$(0.4)			$(0.1)			$(2.6)


(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	2018			2017
Millions
Net Loss		$4.7			$1.6
Prior Service Credit Arising During the Period	(2.1		)	(1.8		)
Amortization of Prior Service Credit	2.1			2.0
Amortization of Loss	(0.8		)	(0.3		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$3.9			$1.5



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2019		$47.9		$9.7
2020		$47.4		$9.7
2021		$47.3		$9.8
2022		$47.1		$9.8
2023		$47.0		$9.7
Years 2024 – 2028		$231.1		$51.1

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, 2019, are as follows:



	Pension		Postretirement Health and Life
Millions
Net Loss	$7.3		$0.4
Prior Service Credit	(0.2	)	(1.7	)
Total Pension and Postretirement Health and Life Cost (Credit)	$7.1		$(1.3)

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Assumptions Used to Determine Benefit Obligation
As of December 31	2018	2017
Discount Rate
Pension	4.39 - 4.53%	3.81 - 3.96%
Postretirement Health and Life	4.47%	3.86%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.10%
Health Care Trend Rates
Trend Rate	5.00 - 6.46%	5.00 - 6.73%
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	2018	2017	2016
Discount Rate	3.81 - 3.96%	4.53 - 4.57%	4.72 - 4.73%
Expected Long-Term Return on Plan Assets
Pension	7.50%	7.50%	8.00%
Postretirement Health and Life	6.00 - 7.50%	6.00 - 7.50%	6.40 - 8.00%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.30%	3.70 - 4.30%

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, 2018, considered a modified RP-2014 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		$2.0	$(1.6)
Effect on Postretirement Health and Life Obligation		$20.7	$(17.2)



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2018		2017		2018		2017
Equity Securities	32	%	53	%	62	%	64	%
Fixed Income Securities	60	%	38	%	34	%	31	%
Private Equity	5	%	5	%	4	%	5	%
Real Estate	3	%	4	%	—		—
	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, 2018 (no shares as of December 31, 2017).

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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, 2018:



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


(a)	Includes VEBAs and irrevocable grantor trusts.

Fair Value

Pension Fair Value



	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	—		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 securities large‑cap, mid-cap and small-cap indexes.

NOTE 15. 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



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—			$108.6	—			$108.6
U.S. Mid-cap Growth (a)	—		51.9		—		51.9
U.S. Small-cap (a)	—		51.5		—		51.5
International	—		122.3		—		122.3
Fixed Income Securities	—		222.8		—		222.8
Cash and Cash Equivalents		$12.4	—		—		12.4
Private Equity Funds	—		—			$33.2	33.2
Real Estate	—		—		25.5		25.5
Total Fair Value of Assets		$12.4		$557.1		$58.7		$628.2


(a)	The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity securities large‑cap, mid-cap and small-cap indexes.



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2016		$40.6			$25.6
Actual Return on Plan Assets	7.1			1.7
Purchases, Sales, and Settlements – Net	(14.5		)	(1.8		)
Balance as of December 31, 2017		$33.2			$25.5

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Postretirement Health and Life Fair Value



	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



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$32.1	—		—			$32.1
U.S. Mid-cap Growth	24.3		—		—		24.3
U.S. Small-cap	15.5		—		—		15.5
International	35.8		—		—		35.8
Fixed Income Securities:
Mutual Funds	49.8		—		—		49.8
Debt Securities	—			$4.5	—		4.5
Cash and Cash Equivalents	0.8		—		—		0.8
Private Equity Funds	—		—			$8.2	8.2
Total Fair Value of Assets		$158.3		$4.5		$8.2		$171.0


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

NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2016		$9.5
Actual Return on Plan Assets	2.6
Purchases, Sales, and Settlements – Net	(3.9		)
Balance as of December 31, 2017		$8.2

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, 2018

Disclosure of Compensation Related Costs, Share-based Payments [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 $11.4 million in 2018 ($11.0 million in 2017; $9.2 million in 2016).

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, 2018, 2017 and 2016.

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 0.9 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, 2018.

The following types of share-based awards were outstanding in 2018, 2017 or 2016:

Non-Qualified Stock Options. Stock options have not been granted since 2008 and none were outstanding as of December 31, 2018 (none in 2017 and an immaterial amount in 2016). These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to 3 months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is eligible for retirement.

The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the grant date. Expected volatility is estimated based on the historic volatility of our stock and the stock of our peer group companies. We utilize historical option exercise and employee pre-vesting termination data to estimate the option life. The dividend growth rate is based upon historical growth rates in our dividends.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

Performance Shares. Under the performance share awards, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies. 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 is determined by 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	2018		2017		2016
Millions
Performance Shares		$2.3		$2.1		$1.8
Restricted Stock Units	0.9		1.0		0.8
Total Share-Based Compensation Expense		$3.2		$3.1		$2.6
Income Tax Benefit		$0.9		$0.9		$1.1

There were no capitalized share-based compensation costs during the years ended December 31, 2018, 2017 or 2016.

As of December 31, 2018, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $3.0 million and $1.0 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years and 1.6 years respectively.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

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



	2018				2017				2016
	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	127,898			$58.23	127,580			$52.56	119,540			$52.72
Granted (a)	66,557			$76.42	50,729			$62.90	57,189			$52.43
Awarded	(58,293	)	$59.82		—		—		—		—
Unearned Grant Award	—		—		(40,801	)		$46.27	(42,126	)		$52.70
Forfeited	(6,469	)		$72.99	(9,610	)		$58.29	(7,023	)		$53.45
Non-vested as of December 31	129,693			$66.12	127,898			$58.23	127,580			$52.56

(a) Shares granted include accrued dividends.

There were 31,843 performance shares granted in January 2019 for the three-year performance period ending in 2021. 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 $2.3 million. There were 73,532 performance shares awarded in February 2019. The grant date fair value of the shares awarded was $3.9 million.

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



	2018				2017				2016
	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	55,248			$56.18	54,728			$51.79	57,694			$49.86
Granted (a)	16,573			$71.11	21,241			$62.20	20,351			$50.25
Awarded	(18,881	)		$55.78	(17,281	)		$49.72	(19,661	)		$44.33
Forfeited	(3,169	)		$64.92	(3,440	)		$56.00	(3,656	)		$52.87
Available as of December 31	49,771			$60.74	55,248			$56.18	54,728			$51.79

(a) Shares granted include accrued dividends.

There were 12,924 restricted stock units granted in January 2019 for the vesting period ending in 2021. The grant date fair value of the restricted stock units granted was $1.0 million. There were 14,307 restricted stock units awarded in February 2019. The grant date fair value of the shares awarded was $0.7 million.

Business Segments Business Segments (Notes)

12 Months Ended

Dec. 31, 2018

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 is our integrated water management company. The ALLETE Clean Energy and U.S. Water Services reportable segments comprise our Energy Infrastructure and Related Services businesses. 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 17. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2018		2017			2016
Millions
Operating Revenue (a)
Residential		$139.7		$127.4			$127.9
Commercial	147.9		139.8			139.5
Municipal	54.9		57.9			67.6
Industrial	469.5		470.5			416.0
Other Power Suppliers	170.3		161.8			175.1
CIP Financial Incentive	3.0		5.5			7.5
Other	74.2		100.9			67.1
Total Regulated Operations	1,059.5		1,063.8			1,000.7

Energy Infrastructure and Related Services

ALLETE Clean Energy
Long-term PSA	55.2		56.9			58.2
Sale of Wind Energy Facility	81.1		—			—
Other	23.6		23.6			22.3
Total ALLETE Clean Energy	159.9		80.5			80.5

U.S. Water Services
Point-in-time	100.3		95.8			93.9
Contract	38.3		36.2			30.4
Capital Project	33.5		19.8			13.2
Total U.S. Water Services	172.1		151.8			137.5

Corporate and Other
Long-term Contract	85.5		89.3			73.7
Other	21.6		33.9			47.3
Total Corporate and Other	107.1		123.2			121.0
Total Operating Revenue		$1,498.6		$1,419.3			$1,339.7
Net Income (Loss) Attributable to ALLETE (b)(c)
Regulated Operations	$131.0		$128.4			$135.5

Energy Infrastructure and Related Services
ALLETE Clean Energy (d)	33.7		41.5			13.4
U.S. Water Services	3.2		10.7			1.5

Corporate and Other (e)	6.2		(8.4		)	4.9
Total Net Income Attributable to ALLETE	$174.1		$172.2			$155.3


(a)	With the adoption of new revenue recognition guidance, the Company has enhanced the presentation of business segment Operating Revenue. (See Note 1. Operations and Significant Accounting Policies.)

(b) 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.)


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


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


(e)	Net income in 2017 included a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of tits November 2016 order on the allocation of North Dakota investment tax credits. Net income in 2016 included an $8.8 million after-tax adverse impact for the regulatory outcome of the November 2016 order.

NOTE 17. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2018			2017			2016
Millions
Depreciation and Amortization
Regulated Operations		$158.0			$132.6			$154.3

Energy Infrastructure and Related Services
ALLETE Clean Energy	24.4			23.4			22.3
U.S. Water Services	10.2			9.8			8.9

Corporate and Other	13.0			11.7			10.3
Total Depreciation and Amortization		$205.6			$177.5			$195.8
Operating Expenses – Other (a)
ALLETE Clean Energy	—			—				$3.3
Corporate and Other	$(2.0)			$(0.7)			(13.6		)
Total Operating Expenses – Other	$(2.0)			$(0.7)			$(10.3)
Interest Expense (b)
Regulated Operations		$60.2			$57.0			$52.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	3.6			4.2			5.8
U.S. Water Services	1.5			1.6			1.7

Corporate and Other	7.3			10.3			14.5

Eliminations	(4.7		)	(5.3		)	(3.8		)
Total Interest Expense		$67.9			$67.8			$70.3
Equity Earnings in ATC
Regulated Operations		$17.5			$22.5			$18.5
Income Tax Expense (Benefit) (c)
Regulated Operations (d)	$(15.5)				$27.2			$5.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	(1.0		)	(14.2		)	8.1
U.S. Water Services	1.0			(7.8		)	1.4

Corporate and Other (d)	—			9.5			4.4
Total Income Tax Expense (Benefit)	$(15.5)			$14.7				$19.8


(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. In 2016, Regulated Operations includes $15.0 million of income tax benefit for North Dakota investment tax credits transferred from Corporate and Other and lower pre-tax income related to the adverse impact for the regulatory outcome of the November 2016 MPUC order. There was no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax expense of $8.8 million in 2016. (See Note 4. Regulatory Matters.)

NOTE 17. BUSINESS SEGMENTS (Continued)



As of December 31	2018		2017
Millions
Assets
Regulated Operations	$3,952.5		$3,886.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	606.6		600.5
U.S. Water Services	295.8		292.4

Corporate and Other	310.1		300.5
Total Assets		$5,165.0		$5,080.0
Capital Expenditures
Regulated Operations	$211.9		$177.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	89.7		56.1
U.S. Water Services	5.0		4.4

Corporate and Other	12.0		28.9
Total Capital Expenditures		$318.6		$266.5

Operations and Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

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 and all of our majority‑owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

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.

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. (See Note 8. Investments.)

We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities.

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 U.S. Water Services and ALLETE Clean Energy segments, 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 in our U.S. Water Services segment and 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, which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. 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.

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 16. Employee Stock and Incentive Plans.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

Goodwill [Policy Text Block]

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Goodwill and Intangible Assets (Continued)

The Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired.

Intangible Assets [Policy Text Block]

Intangible assets include customer relationships, patents, non-compete agreements, land easements, trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents, non-compete agreements, land easements and certain trade names, which are amortized on a straight-line basis with estimated remaining useful lives ranging from approximately 4 years to approximately 19 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite‑lived intangible assets consist of trademarks and certain trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Fair value is generally determined using a discounted cash flow analysis.

When events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable, the Company calculates the excess of an intangible asset's carrying amount over its undiscounted future cash flows. If the carrying amount is not recoverable, an impairment loss is recorded based on the amount by which the carrying amount exceeds the fair value. The inputs used in the fair value analysis fall within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs to determine fair value.

The Company assesses indefinite-lived intangible assets for impairment annually in the fourth quarter. The Company also assesses indefinite-lived and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable.

Environmental Liabilities [Policy Text Block]

Revenue Recognition [Policy Text Block]

Utility

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue (Continued)

Non-utility

ALLETE Clean Energy

U.S. Water Services

Corporate and Other

Revenue from Cost Recovery Riders [Policy Text Block]

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]

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.

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.

Purchase Accounting [Policy Text Block]

In accordance with authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the Consolidated Balance Sheet if it exceeds the estimated fair value and as a bargain purchase gain on the Consolidated Income Statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts as well as the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2017, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.

New Accounting Standards [Policy Text Block]

New Accounting Pronouncements.

Recently Adopted Pronouncements

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Practical Expedients

The following practical expedients were used by the Company as part of the adoption of the new revenue recognition guidance:


•	We have a right to consideration from our customers in an amount that corresponds directly with the value to such customer for performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.


•	We do not adjust the promised amount of consideration for the effects of a significant financing component as at contract inception we expect that the period between when we transfer a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Where applicable, we adopted this guidance using the portfolio approach in which contracts that have similar characteristics were reviewed as a portfolio. The effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying the guidance to each individual contract.


•	We recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that would otherwise have been recognized is one year or less.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Pronouncements

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.

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, no other regulatory assets are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

Equity Method Investments [Policy Text Block]

We account for our investment in ATC under the equity method of accounting.

We account for our investment in Nobles 2 under the equity method of accounting.

The Company assesses our equity investments in ATC and Nobles 2 for impairment whenever events or changes in circumstances indicate that the carrying amount of our investments may not be recoverable.

Fair Value Measurement [Policy Text Block]

We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy.

The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value was measured based on the consideration expected to be transferred, discounted to present value. The discount rate was determined at the time of measurement in accordance with generally accepted valuation methods. The fair value of the acquisition contingent consideration is remeasured to arrive at estimated fair value each reporting period with the change in fair value recognized as income or expense in the Consolidated Statement of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, timing of milestones that trigger payments, and the timing and amount of earnings estimates. Using different valuation assumptions, including earnings projections or discount rates, may result in different fair value measurements and expense (or income) in future periods. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.

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.

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 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.

Power Purchase Agreements [Policy Text Block]

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.

Pension and Other Postretirement Benefit Plans [Policy Text Block]

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations.

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.

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.

Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amount presented in the Consolidated Statement of Cash Flows. During the first quarter of 2018, the Company updated the presentation of its Consolidated Statement of Cash Flows to include restricted cash with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. (See Recently Adopted Pronouncements - Statement of Cash Flows: Restricted Cash.)



Cash, Cash Equivalents and Restricted Cash	December 31, 2018		December 31, 2017		December 31, 2016
Millions
Cash and Cash Equivalents		$69.1		$98.9		$27.5
Restricted Cash included in Prepayments and Other	1.3		2.6		2.2
Restricted Cash included in Other Non-Current Assets	8.6		8.6		8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows		$79.0		$110.1		$38.3

Supplemental Statement of Cash Flow Information [Table Text Block]

Supplemental Statement of Cash Flow Information.



Consolidated Statement of Cash Flows
Year Ended December 31	2018		2017		2016
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$66.0		$64.5		$68.2
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	$(0.1)		$67.2		$(22.0)
Reclassification of Property, Plant and Equipment to Inventory (a)		$46.3	—		—
Capitalized Asset Retirement Costs	$14.2		$(15.6)		$3.7
Camp Ripley Solar Financing	—		—			$15.0
AFUDC–Equity		$1.2		$1.2		$2.1
ALLETE Common Stock Contributed to Pension Plans	—			$13.5	—
ALLETE Common Stock Received for Land Inventory	—		—			$8.0
Long-Term Finance Receivable for Land Inventory	—		—			$12.0

(a)

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2018		2017
Millions
Trade Accounts Receivable
Billed		$121.7		$112.6
Unbilled	24.4		24.6
Less: Allowance for Doubtful Accounts	1.7		2.1
Total Accounts Receivable		$144.4		$135.1

Inventories – Net [Table Text Block]



Inventories – Net
As of December 31	2018			2017
Millions
Fuel (a)		$26.0			$34.8
Materials and Supplies	44.2			46.5
Raw Materials	2.8			2.8
Work in Progress	6.1			4.2
Finished Goods	8.4			8.3
Reserve for Obsolescence	(0.8		)	(0.7		)
Total Inventories – Net		$86.7			$95.9


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

Other Non-Current Assets [Table Text Block]



Other Non-Current Assets
As of December 31	2018		2017
Millions
Contract Assets (a)		$30.7		$31.6
Finance Receivable (b)	10.4		11.0
Other	62.2		65.1
Total Other Non-Current Assets		$103.3		$107.7


(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 reflects the remaining balance due from the ALLETE Properties sale of its Ormond Crossings project and Lake Swamp wetland mitigation bank.

Other Current Liabilities [Table Text Block]



Other Current Liabilities
As of December 31	2018		2017
Millions
Provision for Interim Rate Refund		$40.0	—
PSAs	12.6			$24.5
Contract Liabilities (a)	7.6		8.7
Provision for Tax Reform Refund	10.7		—
Contingent Consideration (b)	3.8		—
Other	53.8		50.0
Total Other Current Liabilities		$128.5		$83.2


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


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 9. Fair Value.)

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities
As of December 31	2018		2017
Millions
Asset Retirement Obligation		$138.6		$122.7
PSAs	76.9		89.5
Contingent Consideration (a)	—		5.4
Other	47.1		49.5
Total Other Non-Current Liabilities		$262.6		$267.1


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 9. Fair Value.)

Operating Expenses – Other [Table Text Block]



Operating Expenses – Other
Year Ended December 31	2018	2017	2016
Millions
Impairment of Goodwill (a)	—	—		$3.3
Change in Fair Value of Contingent Consideration (b)	$(2.0)	$(0.7)	(13.6		)
Total Operating Expenses – Other	$(2.0)	$(0.7)	$(10.3)


(a)	See Goodwill and Intangible Assets.


(b)	See Note 9. Fair Value.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

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



Property, Plant and Equipment
As of December 31	2018			2017
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,490.6			$4,523.7
Construction Work in Progress	251.1			121.6
Accumulated Depreciation	(1,549.6		)	(1,520.5		)
Regulated Operations – Net	3,192.1			3,124.8
ALLETE Clean Energy
Property, Plant and Equipment in Service	488.4			482.5
Construction Work in Progress	164.5			144.9
Accumulated Depreciation	(73.0		)	(60.8		)
ALLETE Clean Energy – Net	579.9			566.6
U.S. Water Services
Property, Plant and Equipment in Service	30.1			24.8
Accumulated Depreciation	(14.0		)	(10.4		)
U.S. Water Services – Net	16.1			14.4
Corporate and Other (a)
Property, Plant and Equipment in Service	214.3			204.7
Construction Work in Progress	6.6			5.0
Accumulated Depreciation	(104.6		)	(93.1		)
Corporate and Other – Net	116.3			116.6
Property, Plant and Equipment – Net		$3,904.4			$3,822.4


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



Estimated Useful Lives of Property, Plant and Equipment (Years)
Regulated Operations		ALLETE Clean Energy	5 to 35
Generation	5 to 50	U.S. Water Services	5 to 39
Transmission	52 to 71	Corporate and Other	3 to 50
Distribution	19 to 68

Asset Retirement Obligations [Table Text Block]



Asset Retirement Obligations
Millions
Obligation as of December 31, 2016		$136.6
Accretion	7.6
Liabilities Settled	(5.9		)
Revisions in Estimated Cash Flows	(15.6		)
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

Jointly-Owned Facilities and Projects (Tables)

12 Months Ended

Dec. 31, 2018

Jointly-Owned Facilities and Projects [Abstract]

Jointly-Owned Facilities and Projects [Table Text Block]

Minnesota Power’s investments in jointly-owned facilities and projects and the related ownership percentages are as follows:



Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
As of December 31, 2018
Boswell Unit 4		$650.1		$229.9		$6.4	80
CapX2020	101.0		11.0		—		9.3 - 14.7
Total		$751.1		$240.9		$6.4
As of December 31, 2017
Boswell Unit 4		$668.2		$222.8		$8.2	80
CapX2020	101.0		8.4		—		9.3 - 14.7
Total		$769.2		$231.2		$8.2

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2018		2017
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)		$218.5		$220.3
Income Taxes (c)	105.5		112.8
Asset Retirement Obligations (d)	32.6		29.6
Boswell 1 & 2 (l)	16.3		—
Manufactured Gas Plant (e)	8.0		8.1
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program (f)	—		3.3
Other	3.6		5.6
Total Non-Current Regulatory Assets		$389.5		$384.7
Current Regulatory Liabilities (a)
Provision for Interim Rate Refund (i)		$40.0	—
Provision for Tax Reform Refund (j)	10.7		—
Transmission Formula Rates	4.4		—
Total Current Regulatory Liabilities	55.1		—
Non-Current Regulatory Liabilities
Income Taxes (c)	396.4			$411.2
Wholesale and Retail Contra AFUDC (h)	64.4		57.9
Provision for Interim Rate Refund (i)	—		23.7
Plant Removal Obligations	25.1		20.3
North Dakota Investment Tax Credits (k)	14.7		14.1
Cost Recovery Riders (g)	6.9		2.2
Transmission Formula Rates	1.6		—
Other	3.0		2.6
Total Non-Current Regulatory Liabilities	512.1		532.0
Total Regulatory Liabilities		$567.2		$532.0


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

(b)


(c)	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 and flow through current income taxes.


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


(e)	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.


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


(g)	The cost recovery rider regulatory liabilities are cash collections from our customers in excess of revenue recognized, 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 liabilities as of December 31, 2018, will be returned within the next two years.


(h)	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.


(i)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in 2019 and includes $23.8 million of discounts provided to EITE customers as of December 31, 2018, that will be offset against interim rate refunds ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(j)	Provision for tax reform refund is expected to be refunded to Minnesota Power customers in the first quarter of 2019 and SWL&P customers in 2019 and 2020. (See Tax Cuts and Jobs Act of 2017.)


(k)	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.


(l)	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.

Equity Investments (Tables)

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

ALLETE's Investment in ATC [Table Text Block]



ALLETE’s Investment in ATC
Year Ended December 31	2018			2017
Millions
Equity Investment Beginning Balance		$118.7			$135.6
Cash Investments	6.2			7.8
Equity in ATC Earnings	17.5			22.5
Distributed ATC Earnings	(15.2		)	(19.3		)
Remeasurement of Deferred Income Taxes (a)	—			(27.9		)
Amortization of the Remeasurement of Deferred Income Taxes	0.9			—
Equity Investment Ending Balance		$128.1			$118.7


(a)	Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2018		2017
Millions
Current Assets		$87.2		$87.7
Non-Current Assets	4,928.8		4,598.9
Total Assets		$5,016.0		$4,686.6
Current Liabilities		$640.0		$767.2
Long-Term Debt	2,014.0		1,790.6
Other Non-Current Liabilities	295.3		240.3
Members’ Equity	2,066.7		1,888.5
Total Liabilities and Members’ Equity		$5,016.0		$4,686.6



Income Statement Data
Year Ended December 31	2018		2017		2016
Millions
Revenue		$690.5		$721.6		$650.8
Operating Expense	358.7		344.9		322.5
Other Expense	108.3		104.1		95.5
Net Income		$223.5		$272.6		$232.8
ALLETE’s Equity in Net Income		$17.5		$22.5		$18.5

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2018

Tonka Water [Member]

Business Acquisition [Line Items]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]



Millions
Assets Acquired
Accounts Receivable	$5.1
Other Current Assets	5.1
Trade Names (a)	0.9
Goodwill (a)(b)	16.9
Other Non-Current Assets	0.2
Total Assets Acquired		$28.2
Liabilities Assumed
Current Liabilities		$9.0
Total Liabilities Assumed		$9.0
Net Identifiable Assets Acquired		$19.2

(a) Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)


(b)	Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill.

Water & Energy Systems Technology [Member]

Business Acquisition [Line Items]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$0.1
Other Current Assets	1.0
Customer Relationships (a)	2.8
Goodwill (a)(b)	4.2
Other Non-Current Assets	0.1
Total Assets Acquired		$8.2
Liabilities Assumed
Current Liabilities		$0.3
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.5
Net Identifiable Assets Acquired		$6.7


(a)	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

The following table summarizes changes to goodwill by reportable segment:



	U.S. Water Services
Millions
Balance as of December 31, 2016		$131.2
Acquired Goodwill (a)	16.9
Other Adjustments (b)	0.2
Balance as of December 31, 2017	148.3
Other Adjustments (b)	0.2
Balance as of December 31, 2018		$148.5


(a)	See Note 6. Acquisitions.


(b)	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 and acquisition of Tonka Water was completed in 2018 resulting in adjustments in those periods to the goodwill recorded at the time of acquisition.

Schedule of Intangible Assets [Table Text Block]

The following table summarizes changes to intangible assets, net, for the year ended December 31, 2018:



	December 31, 2017		Additions		Amortization	December 31, 2018
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$54.7		$0.2	$(4.2)		$50.7
Developed Technology and Other (a)	6.3		2.6		(1.4)	7.5
Total Definite-Lived Intangible Assets	61.0		2.8		(5.6)	58.2
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$77.6		$2.8	$(5.6)		$74.8


(a)	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

Fair Value (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$10.2	—		—			$10.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.9	—		8.9
Cash Equivalents	3.8		—		—		3.8
Total Fair Value of Assets		$14.0		$8.9	—			$22.9

Liabilities: (b)
Deferred Compensation	—			$18.2	—			$18.2
U.S. Water Services Contingent Consideration	—		—			$5.4	5.4
Total Fair Value of Liabilities	—			$18.2		$5.4		$23.6
Total Net Fair Value of Assets (Liabilities)		$14.0	$(9.3)		$(5.4)		$(0.7)


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	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:
Deferred Compensation (b)	—			$19.8	—			$19.8
U.S. Water Services Contingent Consideration (c)	—		—			$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 Investments on the Consolidated Balance Sheet.


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


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

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



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2016		$25.0
Accretion (a)	0.8
Payments (b)	(19.7		)
Changes in Cash Flow Projections	(0.7		)
Balance as of December 31, 2017		$5.4
Accretion (a)	0.4
Changes in Cash Flow Projections	(2.0		)
Balance as of December 31, 2018		$3.8


(a)	Included in Interest Expense on the Consolidated Statement of Income.


(b)	Payments reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, and were paid in 2017.

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, 2018	$1,495.2	$1,534.6
December 31, 2017	$1,513.3	$1,627.6

Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Long-term Debt [Table Text Block]



Long-Term Debt
As of December 31	2018			2017
Millions
First Mortgage Bonds
1.83% Series Due 2018	—				$50.0
8.17% Series Due 2019		$42.0		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
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			—
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Unsecured Term Loan Variable Rate Due 2020	10.0			40.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024	57.2			65.9
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			—
Other Long-Term Debt, 3.11% – 5.75% Due 2019 – 2037	67.7			69.1
Unamortized Debt Issuance Costs	(9.2		)	(10.0		)
Total Long-Term Debt	1,486.0			1,503.3
Less: Due Within One Year	57.5			64.1
Net Long-Term Debt		$1,428.5			$1,439.2

- 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
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28551-108399

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21521-112644

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21538-112644

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Commitments, Guarantees and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018
Millions	2019		2020		2021		2022		2023		Thereafter
Coal, Rail and Shipping Contracts		$20.8		$9.0		$7.5	—		—		—
Operating Leases		$9.9		$7.9		$6.1		$4.9		$3.1		$9.4
Easements		$4.8		$4.9		$4.9		$5.0		$5.1		$136.3
Other (a)		$31.6		$0.3		$0.3	—		—			$0.1
PPAs (b)		$107.3		$115.3		$145.4		$145.7		$145.8		$1,550.7


(a)	Consists of long-term service agreements for 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.)

Minnesota Power has also entered into the following PPAs for the purchase or sale of capacity and energy as of December 31, 2018:



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


(a)	The PPA provides for the purchase of all output from the 10 MW Blanchard solar energy facility to be located in central Minnesota. Construction of the Blanchard solar energy facility is expected to be completed in 2020 and the contract is effective for 25 years beginning upon commercial operation.


(b)	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.


(c)	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.


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


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


(f)	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.


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


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


(i)	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.)


(j)	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.


(k)	Minnesota Power is purchasing 50 MW of energy during off-peak hours and 100 MW of energy during on-peak hours.

Minnesota Power has also entered into the following PSAs for the purchase or sale of capacity and energy as of December 31, 2018:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(a)
PSA 2	50 MW	Capacity	June 2017	May 2019	Fixed
PSA 3	(b)	Capacity	June 2022	May 2025	Fixed
PSA 4	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 is fixed through 2019 with pricing in later years escalating at a fixed rate annually and adjusted for changes in a natural gas index.

Common Stock and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Summary of Common Stock [Table Text Block]



Summary of Common Stock	Shares		Equity
	Thousands		Millions
Balance as of December 31, 2015	49,075			$1,271.4
Employee Stock Purchase Plan	16		0.9
Invest Direct	344		20.0
Options and Stock Awards	65		3.7
Contributions to RSOP	60		3.3
Equity Issuance Program	130		8.0
Received for Sale of Land Inventory	(130	)	(8.0		)
Acquisition of Non-Controlling Interest	—		(4.0		)
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
Contribution 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

Reconciliation of Basic and Diluted Earnings Per Share [Table Text Block]



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
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
Dividends Per Share		$2.24			$2.24
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
Dividends Per Share		$2.14			$2.14
2016
Net Income Attributable to ALLETE		$155.3			$155.3
Average Common Shares	49.3		0.2	49.5
Earnings Per Share		$3.15			$3.14
Dividends Per Share		$2.08			$2.08

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2018			2017			2016
Millions
Current Income Tax Expense (a)
Federal	—			—			—
State	$0.3			$0.3			$0.4
Total Current Income Tax Expense		$0.3			$0.3			$0.4
Deferred Income Tax Expense (Benefit)
Federal (b)	$(26.2)				$12.1			$12.0
Federal – Remeasurement of Deferred Income Taxes (c)	—			(13.0		)	—
State	11.0			15.8			8.1
Investment Tax Credit Amortization	(0.6		)	(0.5		)	(0.7		)
Total Deferred Income Tax Expense (Benefit)	$(15.8)				$14.4			$19.4
Total Income Tax Expense (Benefit)	$(15.5)				$14.7			$19.8

(a)


(b)	For the year ended December 31, 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	2018			2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$158.6			$186.9			$175.6
Statutory Federal Income Tax Rate	21		%	35		%	35		%
Income Taxes Computed at Statutory Federal Rate		$33.3			$65.4			$61.5
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	8.9			10.5			5.6
Production Tax Credits	(45.0		)	(45.1		)	(41.5		)
Regulatory Differences – Excess Deferred Tax Benefit (a)	(8.2		)	1.2			1.4
Change in Fair Value of Contingent Consideration	(0.4		)	—			(3.8		)
Remeasurement of Deferred Income Taxes (b)	—			(13.0		)	—
Other	(4.1		)	(4.3		)	(3.4		)
Total Income Tax Expense (Benefit)	$(15.5)				$14.7			$19.8


(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	2018			2017
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation		$62.2			$65.9
Property-Related	95.2			104.3
NOL Carryforwards	86.1			99.1
Tax Credit Carryforwards	349.8			294.3
Power Sales Agreements	27.5			35.0
Regulatory Liabilities	113.4			117.7
Other	25.1			33.3
Gross Deferred Income Tax Assets	759.3			749.6
Deferred Income Tax Asset Valuation Allowance	(66.5		)	(60.0		)
Total Deferred Income Tax Assets		$692.8			$689.6
Deferred Income Tax Liabilities
Property-Related		$752.5			$758.3
Regulatory Asset for Benefit Obligations	61.0			61.4
Unamortized Investment Tax Credits	32.2			32.8
Partnership Basis Differences	40.8			34.9
Regulatory Assets	29.9			32.0
Other	—			0.7
Total Deferred Income Tax Liabilities		$916.4			$920.1
Net Deferred Income Taxes (a)		$223.6			$230.5


(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	2018	2017
Millions
Federal NOL Carryforwards (a)	$319.0		$375.2
Federal Tax Credit Carryforwards	$256.4	$209.2
State NOL Carryforwards (a)	$305.8	$289.9
State Tax Credit Carryforwards (b)	$27.4	$25.6


(a)	Pre-tax amounts.


(b)	Net of a $66.0 million valuation allowance as of December 31, 2018 ($59.5 million as of December 31, 2017).

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2018			2017			2016
Millions
Balance at January 1		$1.7			$2.0			$2.4
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			0.2
Reductions for Tax Positions Related to Prior Years	(0.2		)	(0.1		)	(0.3		)
Lapse of Statute	(0.1		)	(0.4		)	(0.4		)
Balance as of December 31		$1.6			$1.7			$2.0

Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2018

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2019		$47.9		$9.7
2020		$47.4		$9.7
2021		$47.3		$9.8
2022		$47.1		$9.8
2023		$47.0		$9.7
Years 2024 – 2028		$231.1		$51.1

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	$7.3		$0.4
Prior Service Credit	(0.2	)	(1.7	)
Total Pension and Postretirement Health and Life Cost (Credit)	$7.1		$(1.3)

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



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2018	2017	2016
Discount Rate	3.81 - 3.96%	4.53 - 4.57%	4.72 - 4.73%
Expected Long-Term Return on Plan Assets
Pension	7.50%	7.50%	8.00%
Postretirement Health and Life	6.00 - 7.50%	6.00 - 7.50%	6.40 - 8.00%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.30%	3.70 - 4.30%



Assumptions Used to Determine Benefit Obligation
As of December 31	2018	2017
Discount Rate
Pension	4.39 - 4.53%	3.81 - 3.96%
Postretirement Health and Life	4.47%	3.86%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.10%
Health Care Trend Rates
Trend Rate	5.00 - 6.46%	5.00 - 6.73%
Ultimate Trend Rate	4.50%	4.50%
Year Ultimate Trend Rate Effective	2038	2038

Plan Asset Actual and Target Allocations [Table Text Block]

Following are the current targeted allocations as of December 31, 2018:



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


(a)	Includes VEBAs and irrevocable grantor trusts.



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2018		2017		2018		2017
Equity Securities	32	%	53	%	62	%	64	%
Fixed Income Securities	60	%	38	%	34	%	31	%
Private Equity	5	%	5	%	4	%	5	%
Real Estate	3	%	4	%	—		—
	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	2018			2017
Millions
Accumulated Benefit Obligation		$713.7			$745.4
Change in Benefit Obligation
Obligation, Beginning of Year		$793.2			$743.3
Service Cost	11.0			10.2
Interest Cost	29.6			32.5
Plan Amendments	(1.5		)	—
Plan Curtailments	(6.9		)	—
Actuarial (Gain) Loss	(53.0		)	44.8
Benefits Paid	(49.5		)	(51.0		)
Participant Contributions	24.1			13.4
Obligation, End of Year		$747.0			$793.2
Change in Plan Assets
Fair Value, Beginning of Year		$628.2			$557.5
Actual Return on Plan Assets	(21.2		)	91.6
Employer Contribution (a)	40.5			30.1
Benefits Paid	(49.5		)	(51.0		)
Fair Value, End of Year		$598.0			$628.2
Funded Status, End of Year	$(149.0)			$(165.0)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.6)			$(1.4)
Non-Current Liabilities	$(147.4)			$(163.6)


(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	2018	2017
Millions
Net Loss	$(230.5)	$(236.2)
Prior Service Cost	1.4	—
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	80.1	71.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(149.0)	$(165.0)

Components of Net Periodic Cost [Table Text Block]



Components of Net Periodic Pension Cost
Year Ended December 31	2018			2017			2016
Millions
Service Cost		$11.0			$10.2			$8.1
Non-Service Cost Components (a)
Interest Cost	29.6			32.5			33.2
Expected Return on Plan Assets	(44.4		)	(42.4		)	(43.6		)
Amortization of Loss	11.4			9.9			9.5
Amortization of Prior Service Cost	(0.1		)	—			—
Net Pension Cost		$7.5			$10.2			$7.2


(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	2018		2017
Millions
Projected Benefit Obligation		$747.0		$793.2
Accumulated Benefit Obligation		$713.7		$745.4
Fair Value of Plan Assets		$598.0		$628.2

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	2018		2017
Millions
Net (Gain) Loss	$5.8		$(4.3)
Amortization of Prior Service Cost	0.1		—
Prior Service Cost Arising During the Period	(1.6	)	—
Amortization of Loss	(11.4	)	(9.9	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(7.1)		$(14.2)

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:
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	—		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 securities large‑cap, mid-cap and small-cap indexes.

NOTE 15. 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



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)	—			$108.6	—			$108.6
U.S. Mid-cap Growth (a)	—		51.9		—		51.9
U.S. Small-cap (a)	—		51.5		—		51.5
International	—		122.3		—		122.3
Fixed Income Securities	—		222.8		—		222.8
Cash and Cash Equivalents		$12.4	—		—		12.4
Private Equity Funds	—		—			$33.2	33.2
Real Estate	—		—		25.5		25.5
Total Fair Value of Assets		$12.4		$557.1		$58.7		$628.2


(a)	The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity securities large‑cap, mid-cap and small-cap indexes.



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2016		$40.6			$25.6
Actual Return on Plan Assets	7.1			1.7
Purchases, Sales, and Settlements – Net	(14.5		)	(1.8		)
Balance as of December 31, 2017		$33.2			$25.5

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, 2016		$40.6			$25.6
Actual Return on Plan Assets	7.1			1.7
Purchases, Sales, and Settlements – Net	(14.5		)	(1.8		)
Balance as of December 31, 2017		$33.2			$25.5

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	2018			2017
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$190.1			$173.4
Service Cost	4.7			4.4
Interest Cost	7.1			7.7
Actuarial (Gain) Loss	(15.8		)	15.5
Benefits Paid	(11.6		)	(12.2		)
Participant Contributions	3.6			3.1
Plan Amendments	(2.1		)	(1.8		)
Obligation, End of Year		$176.0			$190.1
Change in Plan Assets
Fair Value, Beginning of Year		$171.0			$154.3
Actual Return on Plan Assets	(9.6		)	24.5
Employer Contribution	1.0			1.3
Participant Contributions	3.6			3.1
Benefits Paid	(11.7		)	(12.2		)
Fair Value, End of Year		$154.3			$171.0
Funded Status, End of Year	$(21.7)			$(19.1)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$0.4			$3.0
Current Liabilities	$(1.0)			$(1.1)
Non-Current Liabilities	$(21.1)			$(21.0)

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	2018		2017
Millions
Net Loss (a)	$(25.0)		$(21.1)
Prior Service Credit	4.6		4.6
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	(1.3	)	(2.6	)
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$(21.7)		$(19.1)


(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	2018			2017			2016
Millions
Service Cost		$4.7			$4.4			$3.9
Non-Service Cost Components (a)
Interest Cost	7.1			7.7			7.4
Expected Return on Plan Assets	(10.9		)	(10.5		)	(11.2		)
Amortization of Loss	0.8			0.3			0.2
Amortization of Prior Service Credit	(2.1		)	(2.0		)	(2.9		)
Net Postretirement Health and Life Credit	$(0.4)			$(0.1)			$(2.6)


(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	2018			2017
Millions
Net Loss		$4.7			$1.6
Prior Service Credit Arising During the Period	(2.1		)	(1.8		)
Amortization of Prior Service Credit	2.1			2.0
Amortization of Loss	(0.8		)	(0.3		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$3.9			$1.5

Unrecognized Postretirement Health and Life Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
As of December 31	2018		2017
Millions
Net Loss	$25.0		$21.1
Prior Service Credit	(4.6	)	(4.6	)
Total Unrecognized Postretirement Health and Life Cost	$20.4		$16.5

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		$2.0	$(1.6)
Effect on Postretirement Health and Life Obligation		$20.7	$(17.2)

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$32.1	—		—			$32.1
U.S. Mid-cap Growth	24.3		—		—		24.3
U.S. Small-cap	15.5		—		—		15.5
International	35.8		—		—		35.8
Fixed Income Securities:
Mutual Funds	49.8		—		—		49.8
Debt Securities	—			$4.5	—		4.5
Cash and Cash Equivalents	0.8		—		—		0.8
Private Equity Funds	—		—			$8.2	8.2
Total Fair Value of Assets		$158.3		$4.5		$8.2		$171.0


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



	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 [Table Text Block]



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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2016		$9.5
Actual Return on Plan Assets	2.6
Purchases, Sales, and Settlements – Net	(3.9		)
Balance as of December 31, 2017		$8.2

Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [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	2018		2017		2016
Millions
Performance Shares		$2.3		$2.1		$1.8
Restricted Stock Units	0.9		1.0		0.8
Total Share-Based Compensation Expense		$3.2		$3.1		$2.6
Income Tax Benefit		$0.9		$0.9		$1.1

Performance Shares [Table Text Block]

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



	2018				2017				2016
	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	127,898			$58.23	127,580			$52.56	119,540			$52.72
Granted (a)	66,557			$76.42	50,729			$62.90	57,189			$52.43
Awarded	(58,293	)	$59.82		—		—		—		—
Unearned Grant Award	—		—		(40,801	)		$46.27	(42,126	)		$52.70
Forfeited	(6,469	)		$72.99	(9,610	)		$58.29	(7,023	)		$53.45
Non-vested as of December 31	129,693			$66.12	127,898			$58.23	127,580			$52.56

(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.



	2018				2017				2016
	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	55,248			$56.18	54,728			$51.79	57,694			$49.86
Granted (a)	16,573			$71.11	21,241			$62.20	20,351			$50.25
Awarded	(18,881	)		$55.78	(17,281	)		$49.72	(19,661	)		$44.33
Forfeited	(3,169	)		$64.92	(3,440	)		$56.00	(3,656	)		$52.87
Available as of December 31	49,771			$60.74	55,248			$56.18	54,728			$51.79

(a) Shares granted include accrued dividends.

Business Segments Business Segment (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

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



Year Ended December 31	2018			2017			2016
Millions
Depreciation and Amortization
Regulated Operations		$158.0			$132.6			$154.3

Energy Infrastructure and Related Services
ALLETE Clean Energy	24.4			23.4			22.3
U.S. Water Services	10.2			9.8			8.9

Corporate and Other	13.0			11.7			10.3
Total Depreciation and Amortization		$205.6			$177.5			$195.8
Operating Expenses – Other (a)
ALLETE Clean Energy	—			—				$3.3
Corporate and Other	$(2.0)			$(0.7)			(13.6		)
Total Operating Expenses – Other	$(2.0)			$(0.7)			$(10.3)
Interest Expense (b)
Regulated Operations		$60.2			$57.0			$52.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	3.6			4.2			5.8
U.S. Water Services	1.5			1.6			1.7

Corporate and Other	7.3			10.3			14.5

Eliminations	(4.7		)	(5.3		)	(3.8		)
Total Interest Expense		$67.9			$67.8			$70.3
Equity Earnings in ATC
Regulated Operations		$17.5			$22.5			$18.5
Income Tax Expense (Benefit) (c)
Regulated Operations (d)	$(15.5)				$27.2			$5.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	(1.0		)	(14.2		)	8.1
U.S. Water Services	1.0			(7.8		)	1.4

Corporate and Other (d)	—			9.5			4.4
Total Income Tax Expense (Benefit)	$(15.5)			$14.7				$19.8


(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)



As of December 31	2018		2017
Millions
Assets
Regulated Operations	$3,952.5		$3,886.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	606.6		600.5
U.S. Water Services	295.8		292.4

Corporate and Other	310.1		300.5
Total Assets		$5,165.0		$5,080.0
Capital Expenditures
Regulated Operations	$211.9		$177.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	89.7		56.1
U.S. Water Services	5.0		4.4

Corporate and Other	12.0		28.9
Total Capital Expenditures		$318.6		$266.5



Year Ended December 31	2018		2017			2016
Millions
Operating Revenue (a)
Residential		$139.7		$127.4			$127.9
Commercial	147.9		139.8			139.5
Municipal	54.9		57.9			67.6
Industrial	469.5		470.5			416.0
Other Power Suppliers	170.3		161.8			175.1
CIP Financial Incentive	3.0		5.5			7.5
Other	74.2		100.9			67.1
Total Regulated Operations	1,059.5		1,063.8			1,000.7

Energy Infrastructure and Related Services

ALLETE Clean Energy
Long-term PSA	55.2		56.9			58.2
Sale of Wind Energy Facility	81.1		—			—
Other	23.6		23.6			22.3
Total ALLETE Clean Energy	159.9		80.5			80.5

U.S. Water Services
Point-in-time	100.3		95.8			93.9
Contract	38.3		36.2			30.4
Capital Project	33.5		19.8			13.2
Total U.S. Water Services	172.1		151.8			137.5

Corporate and Other
Long-term Contract	85.5		89.3			73.7
Other	21.6		33.9			47.3
Total Corporate and Other	107.1		123.2			121.0
Total Operating Revenue		$1,498.6		$1,419.3			$1,339.7
Net Income (Loss) Attributable to ALLETE (b)(c)
Regulated Operations	$131.0		$128.4			$135.5

Energy Infrastructure and Related Services
ALLETE Clean Energy (d)	33.7		41.5			13.4
U.S. Water Services	3.2		10.7			1.5

Corporate and Other (e)	6.2		(8.4		)	4.9
Total Net Income Attributable to ALLETE	$174.1		$172.2			$155.3


(a)	With the adoption of new revenue recognition guidance, the Company has enhanced the presentation of business segment Operating Revenue. (See Note 1. Operations and Significant Accounting Policies.)


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


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


(e)	Net income in 2017 included a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of tits November 2016 order on the allocation of North Dakota investment tax credits. Net income in 2016 included an $8.8 million after-tax adverse impact for the regulatory outcome of the November 2016 order.

Operations and Significant Accounting Policies - Business Segments (Details)	12 Months Ended
	Dec. 31, 2018 a Customers MW	Dec. 31, 2017
Business Segments [Line Items]
Number of Reportable Segments	3	3
Square Butte [Member] \| Square Butte PPA [Member]
Business Segments [Line Items]
Minnesota Power Output Entitlement (MW) \| MW	227.5
Minnesota Power [Member] \| Square Butte [Member] \| Square Butte [Member] \| Square Butte PPA [Member]
Business Segments [Line Items]
Minnesota Power Output Entitlement (Percent)	50.00%
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	16
Regulated Operations [Member] \| SWL&P [Member] \| Retail Customers [Member] \| Electric Rates [Member]
Business Segments [Line Items]
Number of Customers	15,000
Regulated Operations [Member] \| SWL&P [Member] \| Retail Customers [Member] \| Natural Gas [Member]
Business Segments [Line Items]
Number of Customers	13,000
Regulated Operations [Member] \| SWL&P [Member] \| Retail Customers [Member] \| Water [Member]
Business Segments [Line Items]
Number of Customers	10,000
ALLETE Clean Energy [Member] \| ALLETE Clean Energy [Member]
Business Segments [Line Items]
Generating Capacity Owned (MW) \| MW	545
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	2
Corporate and Other [Member] \| BNI Energy [Domain] \| Square Butte [Member]
Business Segments [Line Items]
Number of Customers	1

Operations and Significant Accounting Policies - Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and Cash Equivalents	$ 69.1	$ 98.9	$ 27.5
Restricted Cash included in Prepayments and Other	1.3	2.6	2.2
Restricted Cash included in Other Non-Current Assets	8.6	8.6	8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows	$ 79.0	$ 110.1	$ 38.3	$ 110.7

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

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

$ 66.0

$ 64.5

$ 68.2

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

Increase to Regulatory Assets

0.0

80.9

0.0

Decrease in Investment in ATC

0.0

(27.9)

0.0

Increase (Decrease) in Deferred Income Taxes

0.0

(353.6)

0.0

Increase to Regulatory Liabilities

0.0

393.6

0.0

Noncash Investing and Financing Activities [Abstract]

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

(0.1)

67.2

(22.0)

Reclassification of Property, Plant and Equipment to Inventory

^[1]

46.3

0.0

Capitalized Asset Retirement Costs

14.2

(15.6)

3.7

Camp Ripley Solar Financing

0.0

15.0

AFUDC–Equity

1.2

2.1

ALLETE Common Stock Contributed to the Defined Benefit Pension Plan

0.0

13.5

0.0

ALLETE Common Stock Received for Land Inventory [Member]

Noncash Consideration for Land Inventory [Line Items]

Consideration for Land Inventory

0.0

8.0

Long-Term Finance Receivable for Land Inventory [Member]

Noncash Consideration for Land Inventory [Line Items]

Consideration for Land Inventory

$ 0.0

$ 12.0

[1]

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Accounts Receivable [Abstract]

Billed

$ 121.7

$ 112.6

Unbilled

24.4

24.6

Less: Allowance for Doubtful Accounts

1.7

2.1

Total Accounts Receivable

144.4

135.1

Inventories – Net [Abstract]

Fuel

^[1]

26.0

34.8

Materials and Supplies

44.2

46.5

Raw Materials

2.8

Work in Progress

6.1

4.2

Finished Goods

8.4

8.3

Reserve for Obsolescence

(0.8)

(0.7)

Total Inventories

86.7

95.9

Impairment of Long-Lived Assets [Abstract]

Impairment of Real Estate

0.0

$ 0.0

Goodwill [Line Items]

Impairment of Goodwill

^[2]

0.0

3.3

Definite-Lived Intangible Assets [Line Items]

Provision for Interim Rate Refunds

40.0

0.0

Provision for Tax Reform Refunds

10.7

0.0

Indefinite-Lived Intangible Assets [Abstract]

Impairment of Intangible Assets

0.0

Other Non-Current Assets [Abstract]

Contract Asset - Noncurrent

^[3]

30.7

31.6

Financing Receivable

^[4]

10.4

11.0

Other

62.2

65.1

Total Other Non-Current Assets

103.3

107.7

Other Current Liabilities [Abstract]

PSAs

12.6

24.5

Contract with Customer, Liability, Current

^[5]

7.6

8.7

Business Combination, Contingent Consideration, Liability, Current

^[6]

3.8

0.0

Other

53.8

50.0

Total Other Current Liabilities

128.5

83.2

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

138.6

122.7

PSAs

76.9

89.5

Contingent Consideration

^[7]

0.0

5.4

Other

47.1

49.5

Total Other Non-Current Liabilities

262.6

267.1

Business Segments [Line Items]

Other – Non-utility

23.6

22.3

Operating Expenses – Other [Abstract]

Impairment of Real Estate

0.0

Impairment of Goodwill

^[2]

0.0

3.3

Change in Fair Value of Contingent Consideration

^[8]

(2.0)

(0.7)

(13.6)

Total Operating Expenses – Other

$ (2.0)

$ (0.7)

$ (10.3)

Income Taxes [Abstract]

More-Likely-Than-Not Percentage

50.00%

Remeasurement of Deferred Income Taxes as a Result of the TCJA [Line Items]

Statutory Federal Income Tax Rate

21.00%

35.00%

Deferred Income Tax Expense (Benefit)

$ (15.8)

$ 14.4

$ 19.4

Decrease in Investment in ATC

0.0

(27.9)

0.0

Increase to Regulatory Assets

0.0

80.9

0.0

Increase to Regulatory Liabilities

0.0

393.6

0.0

ALLETE Clean Energy [Member]

Goodwill [Line Items]

Impairment of Goodwill

3.3

Operating Expenses – Other [Abstract]

Impairment of Goodwill

3.3

Total Operating Expenses – Other

^[9]

0.0

3.3

U.S. Water Services [Member]

Goodwill [Line Items]

Impairment of Goodwill

0.0

Operating Expenses – Other [Abstract]

Impairment of Goodwill

0.0

Corporate and Other [Member]

Operating Expenses – Other [Abstract]

Total Operating Expenses – Other

^[9]

$ (2.0)

$ (0.7)

$ (13.6)

Discount Rate [Member] | U.S. Water Services [Member]

Goodwill [Line Items]

Discounted Cash Flow Model Significant Assumptions

0.120

Annual Revenue Growth Rate [Member] | U.S. Water Services [Member] | Minimum [Member]

Goodwill [Line Items]

Discounted Cash Flow Model Significant Assumptions

.060

Annual Revenue Growth Rate [Member] | U.S. Water Services [Member] | Maximum [Member]

Goodwill [Line Items]

Discounted Cash Flow Model Significant Assumptions

.100

Measurement Input, Terminal Growth Rate [Member] | U.S. Water Services [Member]

Goodwill [Line Items]

Discounted Cash Flow Model Significant Assumptions

0.035

Developed Technology and Other [Member] | Minimum [Member]

Definite-Lived Intangible Assets [Line Items]

Useful Life (Years)

4 years

Developed Technology and Other [Member] | Maximum [Member]

Definite-Lived Intangible Assets [Line Items]

Useful Life (Years)

10 years

Customer Relationships [Member]

Definite-Lived Intangible Assets [Line Items]

Useful Life (Years)

19 years

[1]	Fuel consists primarily of coal inventory at Minnesota Power.
[2]	See Goodwill and Intangible Assets.
[3]	Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue.
[4]	Finance Receivable reflects the remaining balance due from the ALLETE Properties sale of its Ormond Crossings project and Lake Swamp wetland mitigation bank.
[5]	Contract Liabilities include deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.
[6]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 9. Fair Value.)
[7]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 9. Fair Value.)
[8]	See Note 9. Fair Value.
[9]	See Note 1. Operations and Significant Accounting Policies.

Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Details)	12 Months Ended
	Dec. 31, 2018 Customers MW
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	50.00%
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]
Length of Notice Required to Terminate Contract	three-year
Number of Customers	16
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	four-year
Contract Serving Requirement \| MW	10
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

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, 2018 USD ($)
Other Power Supplier 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, Amount	$ 75
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	$ 10
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
Revenue, Remaining Performance Obligation, Amount	$ 55
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	$ 25
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	$ 75

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, 2018 USD ($) Customers	Dec. 31, 2017 USD ($) Customers	Dec. 31, 2016 Customers
Concentration Risk [Line Items]
Number of Large Power Customers \| Customers	8	9	9
Receivables from Large Power Customers \| $	$ 11.7	$ 13.8
Largest Customer [Member] \| Consolidated Operating Revenue [Member]
Concentration Risk [Line Items]
Percent of Consolidated Operating Revenue	10.00%	10.00%	8.00%

Operations and Significant Accounting Policies - Revenue - Assets Recognized From the Costs to Obtain a Contract with a Customer (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Capitalized Contract Cost [Line Items]

Contract Asset - Noncurrent

^[1]

$ 30.7

$ 31.6

Capitalized Contract Cost, Amortization

$ 2.6

$ 2.7

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

Operations and Significant Accounting Policies - New Accounting Pronouncements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018
New Accounting Standards [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 0.5
Accounting Standards Update 2018-02 [Member]
New Accounting Standards [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption			$ 5.7
Accounting Standards Update 2017-07 [Member] \| Operating and Maintenance [Member]
New Accounting Standards [Line Items]
Prior Period Reclassification Adjustment	4.2	$ 6.8
Accounting Standards Update 2017-07 [Member] \| Cost of Sales - Non-utility [Member]
New Accounting Standards [Line Items]
Prior Period Reclassification Adjustment	0.3
Accounting Standards Update 2017-07 [Member] \| Other Income/Expense [Member]
New Accounting Standards [Line Items]
Prior Period Reclassification Adjustment	3.9	6.5
Accounting Standards Update 2016-01 [Member]
New Accounting Standards [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	0.1
Accounting Standards Update 2016-15 [Member]
New Accounting Standards [Line Items]
Prior Period Reclassification Adjustment		2.9
Accounting Standards Update 2014-09 [Member]
New Accounting Standards [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	0.5
Accounting Standards Update 2016-02 [Member]
New Accounting Standards [Line Items]
Expected Minimum Lease Payment Due in Future Years			$ 36.0
Financing Activities [Member] \| Accounting Standards Update 2016-18 [Member]
New Accounting Standards [Line Items]
Prior Period Reclassification Adjustment	$ 0.4	0.7
Investing Activities [Member] \| Accounting Standards Update 2016-18 [Member]
New Accounting Standards [Line Items]
Prior Period Reclassification Adjustment		$ 4.1

Operations and Significant Accounting Policies - Consolidated Statement of Income (Details)	12 Months Ended
	Dec. 31, 2018
Out-of-Period Adjustment for MISO Rates [Domain]
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Immaterial Error Correction	In 2018, we recognized a $4.4 million reduction in revenue for MISO rates that were billed in 2017 and are expected to be credited to customers in 2019. We have evaluated the effect of this out-of-period adjustment on the years ended December 31, 2018, and 2017, and concluded that this adjustment is not material to any of the periods affected.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment – Net

$ 3,904.4

$ 3,822.4

Asset Retirement Obligation [Roll Forward]

Beginning Obligation

122.7

136.6

Accretion

7.0

7.6

Liabilities Settled

(5.3)

(5.9)

Revisions in Estimated Cash Flows

14.2

(15.6)

$ 3.7

Ending Obligation

138.6

122.7

$ 136.6

Regulated Operations [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment in Service

4,490.6

4,523.7

Construction Work in Progress

251.1

121.6

Accumulated Depreciation

(1,549.6)

(1,520.5)

Property, Plant and Equipment – Net

$ 3,192.1

3,124.8

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

$ 488.4

482.5

Construction Work in Progress

164.5

144.9

Accumulated Depreciation

(73.0)

(60.8)

Property, Plant and Equipment – Net

$ 579.9

566.6

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

$ 30.1

24.8

Accumulated Depreciation

(14.0)

(10.4)

Property, Plant and Equipment – Net

$ 16.1

14.4

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

^[1]

$ 214.3

204.7

Construction Work in Progress

^[1]

6.6

5.0

Accumulated Depreciation

^[1]

(104.6)

(93.1)

Property, Plant and Equipment – Net

$ 116.3

$ 116.6

Corporate and Other [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

3 years

Corporate and Other [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

50 years

[1]	Primarily includes BNI Energy and a small amount of non-rate base generation.

Jointly-Owned Facilities and Projects (Details) $ in Millions	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 751.1	$ 769.2
Accumulated Depreciation	240.9	231.2
Construction Work in Progress	6.4	8.2
Transmission [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	101.0	101.0
Accumulated Depreciation	11.0	8.4
Construction Work in Progress	$ 0.0	$ 0.0
Transmission [Member] \| CapX2020 Projects [Member] \| Minimum [Member]
Jointly-Owned Facilities and Projects [Line Items]
Minnesota Power Ownership %	9.30%	9.30%
Transmission [Member] \| CapX2020 Projects [Member] \| Maximum [Member]
Jointly-Owned Facilities and Projects [Line Items]
Minnesota Power Ownership %	14.70%	14.70%
Boswell Unit 4 [Member] \| Jointly-Owned Electricity Generation Plant [Member]
Jointly-Owned Facilities and Projects [Line Items]
Minnesota Power Ownership %	80.00%	80.00%
Generating Capacity Jointly Owned (MW) \| MW	585
Plant in Service	$ 650.1	$ 668.2
Accumulated Depreciation	229.9	222.8
Construction Work in Progress	$ 6.4	$ 8.2
Boswell Unit 4 [Member] \| Jointly-Owned Electricity Generation Plant [Member] \| Minnesota Power [Member]
Jointly-Owned Facilities and Projects [Line Items]
Minnesota Power Ownership %	80.00%
Boswell Unit 4 [Member] \| Jointly-Owned Electricity Generation Plant [Member] \| WPPI Energy [Member]
Jointly-Owned Facilities and Projects [Line Items]
WPPI Energy Ownership %	20.00%

Regulatory Matters - Electric Rates (Details) $ in Millions					1 Months Ended	12 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Dec. 20, 2018 USD ($)	May 25, 2018	Jan. 18, 2018 USD ($)	Aug. 09, 2017	Nov. 30, 2016	Dec. 31, 2018 USD ($) Customers Years MW	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Regulatory Matters [Line Items]
Charge to Fuel, Purchased Power and Gas - Utility						$ 407.5	$ 396.9	$ 339.9
MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Charge to Fuel, Purchased Power and Gas - Utility						19.5
MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Boswell Energy Center [Member]
Regulatory Matters [Line Items]
Decrease in Annual Depreciation Expense Based on Regulatory Order						$ 25.0
PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity				10.50%
Approved Equity Ratio				55.00%
PSCW [Member] \| 2012 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity						10.90%
PSCW [Member] \| 2018 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase		2.70%
Requested Return on Equity		10.50%
Requested Equity Ratio		55.41%
Approved Return on Common Equity	10.40%
Approved Equity Ratio	55.00%
Approved Rate Increase - Amount	$ 1.3
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						$ 103.8	96.9	97.1
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase					9.00%
Requested Return on Equity					10.25%
Requested Equity Ratio					53.81%
Approved Return on Common Equity			9.25%
Approved Equity Ratio			53.81%
Annual Additional Revenue Generated from Requested Final Rate Increase			$ 13.0
Reserve for Interim Rate Refund						40.0	23.7
Electric Rates [Member] \| MPUC [Member] \| Energy-Intensive Trade-Exposed Customer Rates [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Estimated Discount to be Provided During the Next Twelve Months						16.0
Discount Provided to EITE Customers						$ 16.7	8.6	0.0
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Retail Customers [Member] \| Corporate and Other [Member]
Regulatory Matters [Line Items]
After-Tax Change for North Dakota Investment Tax Credits Reversed							7.9	8.8
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase - Amount							$ 14.0	$ 15.0
Electric Rates [Member] \| MPUC [Member] \| Tax Cuts and Jobs Act [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Amortization Period of the Income Tax Benefits from the Remeasurement of Deferred Income Tax Assets and Liabilities Resulting from the TCJA Excluding the Related Property Plant and Equipment						10 years
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers						16
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 (Termination Effective June 2019) [Member]
Regulatory Matters [Line Items]
Average Monthly Demand (MW) \| MW						29
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						3
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] \| PSCW [Member] \| Tax Cuts and Jobs Act [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Amortization Period of the Income Tax Benefits from the Remeasurement of Deferred Income Tax Assets and Liabilities Resulting from the TCJA Excluding the Related Property Plant and Equipment	4 years
Electric Rates [Member] \| PSCW [Member] \| 2018 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase		2.00%
Natural Gas Rates [Member] \| PSCW [Member] \| 2018 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase		2.30%
Water Rates [Member] \| PSCW [Member] \| 2018 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase		8.30%

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - MW	Jul. 28, 2017	Aug. 22, 2018	Jun. 18, 2018	Dec. 31, 2016
Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Output Being Purchased (MW)	250
Natural Gas-Fired [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Expected Output Entitlement (Percent)	50.00%
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
Natural Gas-Fired [Member] \| Minimum [Member] \| Minnesota Power [Member] \| Integrated Resource Plan [Member]
Regulatory Matters [Line Items]
Additional Natural Gas-fired Generation (MW)				200
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)	550
Natural Gas-Fired [Member] \| Maximum [Member] \| Minnesota Power [Member] \| Integrated Resource Plan [Member]
Regulatory Matters [Line Items]
Additional Natural Gas-fired Generation (MW)				300
Wind Turbine Generators [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Nobles 2 [Member] \| Nobles 2 [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)	250	250
Solar Energy Generation [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Solar Energy PPA [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)	10		10

Regulatory Matters - Great Northern Transmission Line (Details) - Great Northern Transmission Line [Member] $ in Millions	Dec. 31, 2018 USD ($) kV Miles
Regulatory Matters [Line Items]
Total Project Costs Incurred to Date	$ 380.8
Minimum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	560.0
Maximum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	$ 710.0
Minnesota Power [Member]
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Minnesota Power [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	$ 300.0
Minnesota Power [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	350.0
Manitoba Hydro [Member]
Regulatory Matters [Line Items]
Project Costs Recovered from Counterparty	$ 203.7
MPUC [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500

Regulatory Matters - Conservation Improvement Program (CIP) (Details) - MPUC [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CIP Triennial Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Investment Goal	$ 10.3	$ 10.3	$ 7.3
CIP Actual Spending	9.0	8.1	7.4
CIP Investment Goal in 2019	10.5
CIP Consolidated Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Financial Incentive	$ 3.0	$ 5.5	$ 7.5
Minimum [Member]
Regulatory Matters [Line Items]
CIP Spending Minimum - Percentage	1.50%

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Dec. 31, 2018
Loss Contingencies [Line Items]
FERC Authorized Return on Common Equity	10.32%
FERC Authorized Return on Equity Including Incentive Adder	10.82%
Return on Equity Complaint [Member]
Loss Contingencies [Line Items]
Proposed Return on Equity by Federal Administrative Law Judge	9.70%
Proposed Return on Equity by Federal Administrative Law Judge Including Incentive Adder	10.20%

Regulatory Matters - Minnesota Solar Energy Standard (Details) - MPUC [Member] - MW	Dec. 31, 2018	Oct. 02, 2018
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
Minnesota Solar Energy Standard - Blanchard Solar Energy Facility [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Counterparty Owned (MW)		10
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, 2018

Dec. 31, 2017

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, no other regulatory assets are currently earning a return.

Non-Current Regulatory Assets

$ 389.5

$ 384.7

Current Regulatory Liability

55.1

0.0

Non-Current Regulatory Liabilities

512.1

532.0

Total Regulatory Liabilities

567.2

532.0

Minnesota Power [Member] | Retail Customers [Member] | Electric Rates [Member] | Energy-Intensive Trade-Exposed Customer Rates [Member] | MPUC [Member]

Regulatory Assets and Liabilities [Line Items]

Provided Discounts to EITE Customers to be Offset Against Interim Rate Refunds

23.8

8.6

Provision for Interim Rate Refund [Domain]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Liability

^[1],[2]

40.0

0.0

Provision for Tax Reform Refund [Domain]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Liability

^[1],[3]

10.7

0.0

Transmission Formula Rates [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Liability

^[1]

4.4

0.0

Non-Current Regulatory Liabilities

1.6

0.0

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[4]

396.4

411.2

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[5]

64.4

57.9

Revenue Subject to Refund [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[2]

0.0

23.7

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

25.1

20.3

North Dakota Investment Tax Credits [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[6]

14.7

14.1

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

^[7]

6.9

2.2

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

3.0

2.6

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[8]

218.5

220.3

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[4]

105.5

112.8

Asset Retirement Obligation [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[9]

32.6

29.6

Boswell 1 & 2 [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[10]

16.3

0.0

Manufactured Gas Plant [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[11]

8.0

8.1

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

5.0

CIP Financial Incentive [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[12]

0.0

3.3

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

$ 3.6

$ 5.6

Regulatory Clause Revenues, under-recovered [Member]

Regulatory Assets and Liabilities [Line Items]

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 is expected to be refunded to Minnesota Power’s regulated retail customers in 2019 and includes $23.8 million of discounts provided to EITE customers as of December 31, 2018, that will be offset against interim rate refunds ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)
[3]	Provision for tax reform refund is expected to be refunded to Minnesota Power customers in the first quarter of 2019 and SWL&P customers in 2019 and 2020. (See Tax Cuts and Jobs Act of 2017.)
[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 and flow through current income taxes.
[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]	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.
[7]	The cost recovery rider regulatory liabilities are cash collections from our customers in excess of revenue recognized, 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 liabilities as of December 31, 2018, will be returned within the next two years.
[8]	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 15. Pension and Other Postretirement Benefit Plans.)
[9]	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
[10]	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.
[11]	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.
[12]	The conservation improvement program regulatory asset represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future cost recovery over the next year following MPUC approval.

Equity Investments (Details)
$ in Millions

12 Months Ended

Jan. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

ALLETE's Investment in ATC [Roll Forward]

Equity Investment Beginning Balance

$ 118.7

Cash Investments

39.2

$ 7.8

$ 5.4

Equity Earnings in ATC

17.5

22.5

18.5

Equity Investment Ending Balance

161.1

118.7

Income Statement Data [Abstract]

ALLETE's Equity in Net Income

$ 17.5

22.5

18.5

FERC [Member] | Return on Equity Complaint 2 [Member]

Income Statement Data [Abstract]

Proposed Return on Equity

9.70%

Proposed Return on Equity, Including Incentive Adder

10.20%

ATC [Member]

Equity Investments [Line Items]

Ownership Percentage

8.00%

Expected Additional Investment in 2019

$ 8.5

ALLETE's Investment in ATC [Roll Forward]

Equity Investment Beginning Balance

118.7

135.6

Cash Investments

6.2

7.8

Equity Earnings in ATC

17.5

22.5

18.5

Distributed ATC Earnings

(15.2)

(19.3)

Remeasurement of Deferred Income Taxes for Equity Method Investments

^[1]

0.0

(27.9)

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

0.9

0.0

Equity Investment Ending Balance

128.1

118.7

135.6

Balance Sheet Data [Abstract]

Current Assets

87.2

87.7

Non-Current Assets

4,928.8

4,598.9

Total Assets

5,016.0

4,686.6

Current Liabilities

640.0

767.2

Long-Term Debt

2,014.0

1,790.6

Other Non-Current Liabilities

295.3

240.3

Members' Equity

2,066.7

1,888.5

Total Liabilities and Members' Equity

5,016.0

4,686.6

Income Statement Data [Abstract]

Revenue

690.5

721.6

650.8

Operating Expense

358.7

344.9

322.5

Other Expense

108.3

104.1

95.5

Net Income

223.5

272.6

232.8

ALLETE's Equity in Net Income

$ 17.5

$ 22.5

$ 18.5

Authorized Return on Equity

10.32%

Authorized Return on Equity, Including Incentive Adder

10.82%

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%

ALLETE's Investment in ATC [Roll Forward]

Equity Investment Ending Balance

$ 33.0

Nobles 2 [Member] | Minimum [Member]

Income Statement Data [Abstract]

Estimated Project Cost

350.0

Portion of Expected Project Costs

170.0

Expected Tax Equity Financing

60.0

Nobles 2 [Member] | Maximum [Member]

Income Statement Data [Abstract]

Estimated Project Cost

400.0

Portion of Expected Project Costs

200.0

Expected Tax Equity Financing

$ 70.0

Equity Investments [Line Items]

Generating Capacity to be Counterparty Owned (MW) | MW

^[2]

250

Contract Term (Years)

20 years

[1]	Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.
[2]	The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.

Acquisitions - Tonka Water (Details) - Tonka Water [Member] $ in Millions	Sep. 01, 2017 USD ($)
Business Acquisition [Line Items]
Percentage of Voting Interests Acquired	100.00%
Name of Acquired Entity	Tonka Water
Total Consideration	$ 19.2
Payments to Acquire Business	19.0
Assets Acquired [Abstract]
Accounts Receivable	5.1
Other Current Assets	5.1
Trade Names	0.9
Goodwill	16.9
Other Non-Current Assets	0.2
Total Assets Acquired	28.2
Liabilities Assumed [Abstract]
Current Liabilities	9.0
Total Liabilities Assumed	9.0
Net Identifiable Assets Acquired	19.2
Tax Deductible Goodwill	4.1
Working Capital Adjustment Paid in the Fourth Quarter 2017	$ 0.2

Acquisitions - Acquisition of Non-Controlling Interest (Details) - USD ($) $ in Millions		12 Months Ended
	Apr. 15, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Acquisition of Non-Controlling Interest [Line Items]
Payments to Acquire Additional Interest in Subsidiaries		$ 0.0	$ 0.0	$ 8.0
ALLETE Clean Energy [Member]
Acquisition of Non-Controlling Interest [Line Items]
Payments to Acquire Additional Interest in Subsidiaries	$ 8.0
Gain or Loss Recognized in Net Income or Other Comprehensive Income	$ 0.0

Acquisitions - WEST (Details) - Water & Energy Systems Technology [Member] - USD ($)
$ in Millions

1 Months Ended

6 Months Ended

Oct. 11, 2016

Oct. 31, 2016

Jun. 30, 2017

Business Acquisition [Line Items]

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Water & Energy Systems Technology of Nevada, Inc.

Total Consideration

$ 6.7

Payments to Acquire Business

5.9

Working Capital Adjustments

$ 0.2

Payments Due in April 2018

$ 0.6

Assets Acquired [Abstract]

Cash and Cash Equivalents

$ 0.1

Other Current Assets

1.0

Intangible Assets

^[1]

2.8

Goodwill

^[1],[2]

4.2

Other Non-Current Assets

0.1

Total Assets Acquired

8.2

Liabilities Assumed [Abstract]

Current Liabilities

0.3

Non-Current Liabilities

1.2

Total Liabilities Assumed

1.5

Net Identifiable Assets Acquired

6.7

Tax Deductible Goodwill

$ 0.0

[1]	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)
[2]	For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Goodwill and Intangible Assets - Goodwill (Details) - U.S. Water Services [Member] - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Goodwill [Roll Forward]

Beginning Balance

$ 148.3

$ 131.2

Acquired Goodwill

^[1]

16.9

Other Adjustments

^[2]

0.2

Ending Balance

$ 148.5

$ 148.3

[1]	See Note 6. Acquisitions.
[2]	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 and acquisition of Tonka Water was completed in 2018 resulting in adjustments in those periods to the goodwill recorded at the time of acquisition.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

$ 61.0

Additions

2.8

Amortization

(5.6)

$ (5.5)

$ (5.2)

Ending Balance

58.2

61.0

Definite-Lived Intangible Assets, Estimated Annual Amortization Expense [Abstract]

5.3

4.9

4.9

4.6

4.3

34.2

Intangible Assets [Abstract]

Total Intangible Assets

74.8

77.6

Total Intangible Assets, Additions

2.8

Total Intangible Assets, Amortization

(5.6)

(5.5)

$ (5.2)

Accumulated Amortization

$ 20.4

14.8

Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Useful Life (Years)

6 years

Trademarks and Trade Names [Member]

Indefinite-Lived Intangible Assets [Roll Forward]

Beginning Balance

$ 16.6

Additions

0.0

Ending Balance

16.6

Customer Relationships [Member]

Definite-Lived Intangible Assets [Roll Forward]

54.7

0.2

(4.2)

$ 50.7

54.7

Useful Life (Years)

19 years

Intangible Assets [Abstract]

Total Intangible Assets, Amortization

$ (4.2)

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

^[1]

6.3

Additions

^[1]

2.6

Amortization

^[1]

(1.4)

Ending Balance

^[1]

7.5

$ 6.3

Intangible Assets [Abstract]

Total Intangible Assets, Amortization

^[1]

$ (1.4)

Developed Technology and Other [Member] | Minimum [Member]

Definite-Lived Intangible Assets [Roll Forward]

Useful Life (Years)

4 years

Developed Technology and Other [Member] | Maximum [Member]

Definite-Lived Intangible Assets [Roll Forward]

Useful Life (Years)

10 years

Developed Technology and Other [Member] | Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Useful Life (Years)

17 years

[1]	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

Investments (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Investments [Abstract]

ALLETE Properties

$ 24.4

$ 26.4

Available-for-sale Securities

^[1]

20.2

19.1

Cash Equivalents

1.0

3.8

Other

3.5

3.8

Total Other Investments

49.1

$ 53.1

Available-for-sale Corporate Debt Securities, Maturities [Abstract]

One Year or Less

2.0

One Year to Less Than Three Years

2.9

Three Years to Less Than Five Years

2.6

Five or More Years

$ 0.5

[1]

As of December 31, 2018, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $2.0 million, in one year to less than three years was $2.9 million, in three years to less than five years was $2.6 million, and in five or more years was $0.5 million.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Investments [Abstract]

Cash Equivalents

$ 1.0

$ 3.8

Recurring Fair Value Measures [Member]

Investments [Abstract]

Available-for-sale – Equity Securities

^[1]

12.2

10.2

Available-for-sale – Corporate and Governmental Debt Securities

^[1]

8.0

8.9

Cash Equivalents

^[1]

1.0

3.8

Total Fair Value of Assets

21.2

22.9

Liabilities [Abstract]

Deferred Compensation

^[2]

19.8

18.2

U.S. Water Services Contingent Consideration

3.8

^[3]

5.4

^[2]

Total Fair Value of Liabilities

23.6

Total Net Fair Value of Assets (Liabilities)

(2.4)

(0.7)

Activity in Level 3 [Roll Forward]

Fair Value Hierarchy Transfers, All Levels

0.0

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

Investments [Abstract]

Available-for-sale – Equity Securities

^[1]

12.2

10.2

Available-for-sale – Corporate and Governmental Debt Securities

^[1]

0.0

Cash Equivalents

^[1]

1.0

3.8

Total Fair Value of Assets

13.2

14.0

Liabilities [Abstract]

Deferred Compensation

^[2]

0.0

U.S. Water Services Contingent Consideration

0.0

^[3]

0.0

^[2]

Total Fair Value of Liabilities

0.0

Total Net Fair Value of Assets (Liabilities)

13.2

14.0

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]

8.0

8.9

Cash Equivalents

^[1]

0.0

Total Fair Value of Assets

8.0

8.9

Liabilities [Abstract]

Deferred Compensation

^[2]

19.8

18.2

U.S. Water Services Contingent Consideration

0.0

^[3]

0.0

^[2]

Total Fair Value of Liabilities

19.8

18.2

Total Net Fair Value of Assets (Liabilities)

(11.8)

(9.3)

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

Cash Equivalents

^[1]

0.0

Total Fair Value of Assets

0.0

Liabilities [Abstract]

Deferred Compensation

^[2]

0.0

U.S. Water Services Contingent Consideration

3.8

^[3]

5.4

^[2]

Total Fair Value of Liabilities

3.8

5.4

Total Net Fair Value of Assets (Liabilities)

(3.8)

(5.4)

Activity in Level 3 [Roll Forward]

Beginning Balance

5.4

25.0

Ending Balance

3.8

5.4

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

Activity in Level 3 [Roll Forward]

Activity in Level 3

^[4]

(0.4)

(0.8)

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

Activity in Level 3 [Roll Forward]

Activity in Level 3

^[5]

19.7

Recurring Fair Value Measures [Member] | Level 3 [Member] | Changes in Cash Flow Projections [Member]

Activity in Level 3 [Roll Forward]

Activity in Level 3

$ 2.0

$ 0.7

[1]	Included in Other Investments on the Consolidated Balance Sheet.
[2]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[3]	Included in Other Current Liabilities on the Consolidated Balance Sheet.
[4]	Included in Interest Expense on the Consolidated Statement of Income.
[5]	Payments reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, and were paid in 2017.

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,495.2	$ 1,513.3
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,534.6	$ 1,627.6

Fair Value - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Equity Investments

$ 161.1

$ 118.7

Goodwill, Impairment Charge

^[1]

0.0

$ 3.3

Intangible Assets, Carrying Amount

74.8

77.6

Intangible Assets, Indicators of Impairment

0.0

U.S. Water Services [Member]

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Goodwill, Carrying Amount

148.5

148.3

131.2

Goodwill, Impairment Charge

0.0

ALLETE Clean Energy [Member]

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Goodwill, Impairment Charge

3.3

ATC [Member]

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Equity Investments

128.1

118.7

135.6

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member]

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Intangible Assets, Carrying Amount

74.8

77.6

Intangible Assets, Indicators of Impairment

0.0

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] | U.S. Water Services [Member]

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Goodwill, Carrying Amount

148.5

148.3

Goodwill, Impairment Charge

0.0

$ 0.0

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] | Corporate and Other [Member]

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Line Items]

Property, Plant and Equipment, Indicators of Impairment

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

[1]	See Goodwill and Intangible Assets.

Short-Term and Long-Term Debt - Short-Term Debt (Details) - USD ($) $ in Millions	Jan. 10, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Short-Term Debt - Outstanding		$ 57.5	$ 64.1
Short-Term Debt - Unamortized Debt Issuance Costs		0.4
Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity		407.0	407.0
Standby Letters of Credit Outstanding		18.4	11.9
Draws Outstanding		0.0	$ 0.0
ALLETE Amended and Restated Credit Agreement [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity		$ 400.0
Subsequent Event [Member] \| Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	$ 400.0
Line of Credit Facility Additional Borrowing Capacity	150.0
Letters of Credit Maximum Issuances	$ 60.0

Short-Term and Long-Term Debt - Long-Term Debt (Details) $ in Millions				12 Months Ended
	Oct. 17, 2018 USD ($)	Oct. 03, 2018 USD ($)	Apr. 16, 2018 USD ($)	Dec. 31, 2018 USD ($) Years	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Long-Term Debt				$ 1,428.5	$ 1,439.2
Long-Term Debt - Unamortized Debt Issuance Costs				8.8
Debt Instrument [Abstract]
Long-Term Debt Maturing in 2019				57.9
Long-Term Debt Maturing in 2020				113.7
Long-Term Debt Maturing in 2021				98.5
Long-Term Debt Maturing in 2022				89.3
Long-Term Debt Maturing in 2023				88.5
Long-Term Debt Maturing Thereafter				1,047.3
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 Bonds 4.07% Due April 2048 [Member]
Debt Instrument [Abstract]
Proceeds from Issuance of First Mortgage Bond			$ 60.0
Interest Rate			4.07%	4.07%
Unsecured Term Loan Due in 2020 [Member]
Debt Instrument [Abstract]
Repayments of Debt	$ 10.0	$ 20.0

Short-Term and Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Apr. 16, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt	$ 1,495.2		$ 1,513.3
Unamortized Debt Issuance Costs	(9.2)		(10.0)
Total Long-Term Debt	1,486.0		1,503.3
Less: Due Within One Year	57.5		64.1
Net Long-Term Debt	$ 1,428.5		1,439.2
First Mortgage Bonds - 1.83% Series Due 2018 [Member]
Debt Instrument [Line Items]
Interest Rate	1.83%
Long-term Debt	$ 0.0		50.0
First Mortgage Bonds - 8.17% Series Due 2019 [Member]
Debt Instrument [Line Items]
Interest Rate	8.17%
Long-term Debt	$ 42.0		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 - 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%	4.07%
Long-term Debt	$ 60.0		0.0
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	$ 10.0		40.0
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	$ 57.2		65.9
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		0.0
Other Long-Term Debt, 3.11% – 5.75% Due 2019 – 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 67.7		$ 69.1
Minimum [Member] \| Other Long-Term Debt, 3.11% – 5.75% Due 2019 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate	3.11%
Maximum [Member] \| Other Long-Term Debt, 3.11% – 5.75% Due 2019 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate	5.75%

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

Dec. 31, 2018

USD ($)

Coal, Rail and Shipping Contracts [Member]

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

Minimum Payments in 2019

$ 20.8

Minimum Payments in 2020

9.0

Minimum Payments in 2021

7.5

Minimum Payments in 2022

0.0

Minimum Payments in 2023

0.0

Minimum Payments Thereafter

0.0

Leasing Agreements [Member]

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

Minimum Payments in 2019

9.9

Minimum Payments in 2020

7.9

Minimum Payments in 2021

6.1

Minimum Payments in 2022

4.9

Minimum Payments in 2023

3.1

Minimum Payments Thereafter

9.4

Easements [Member]

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

Minimum Payments in 2019

4.8

Minimum Payments in 2020

4.9

Minimum Payments in 2021

4.9

Minimum Payments in 2022

5.0

Minimum Payments in 2023

5.1

Minimum Payments Thereafter

136.3

Long-Term Service Agreements [Member]

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

Minimum Payments in 2019

31.6

^[1]

Minimum Payments in 2020

0.3

^[1]

Minimum Payments in 2021

0.3

^[1]

Minimum Payments in 2022

0.0

^[1]

Minimum Payments in 2023

0.0

^[1]

Minimum Payments Thereafter

0.1

^[1]

PPAs [Member]

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

Minimum Payments in 2019

107.3

^[2]

Minimum Payments in 2020

115.3

^[2]

Minimum Payments in 2021

145.4

^[2]

Minimum Payments in 2022

145.7

^[2]

Minimum Payments in 2023

145.8

^[2]

Minimum Payments Thereafter

$ 1,550.7

^[2]

[1]	Consists of long-term service agreements for wind energy facilities.
[2]	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, 2018

USD ($)

MWh

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

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

Power Purchase Agreements [Line Items]

PPA Counterparty Total Debt Outstanding | $

$ 304.0

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

Power Purchase Agreements [Line Items]

Cost of Purchased Power | $

78.0

$ 75.7

$ 73.3

Pro Rata Share of PPA Counterparty Interest Expense | $

$ 9.1

$ 9.4

$ 9.6

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 Counterparty Annual Debt Service through 2023 | $

$ 48.7

PPA Annual Debt Service Obligation (Percentage)

50.00%

Cypress Creek Renewables [Member] | Cypress Creek Renewables PPA [Member] | Blanchard Solar Energy Facility [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy and Capacity (MW)

Contract Length (Years)

25 years

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

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)

TransAlta [Member] | TransAlta Off-Peak Hours PPA (expires 2019) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy (MW)

TransAlta [Member] | TransAlta On-Peak Hours PPA (expire 2019) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy (MW)

100

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)

Shell Energy [Member] | Shell Energy PPA [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Purchased - Electric Energy (MW)

Basin [Member] | Basin Power Sales Agreement (expires 2019) [Member] | Minnesota Power [Member]

Power Purchase Agreements [Line Items]

Output Being Sold Electric - 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)

[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 - Leasing Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Leasing Agreements [Line Items]
Total Lease Expense	$ 14.6	$ 17.5	$ 17.1
BNI Energy [Member] \| BNI Energy Dragline [Member]
Leasing Agreements [Line Items]
Minimum Payments in 2019	2.8
Minimum Payments in 2020	2.8
Minimum Payments in 2021	2.8
Minimum Payments in 2022	2.8
Minimum Payments in 2023	2.8
Minimum Payments Thereafter	11.2
Termination Fee	$ 3.0

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	Dec. 31, 2018 USD ($) kV Miles MW
Great Northern Transmission Line [Member]
Transmission [Line Items]
Total Project Costs Incurred to Date	$ 380.8
Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	560.0
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	710.0
Manitoba Hydro [Member] \| Great Northern Transmission Line [Member]
Transmission [Line Items]
Project Costs Recovered from Counterparty	$ 203.7
Minnesota Power [Member] \| Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Minnesota Power [Member] \| Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	$ 300.0
Minnesota Power [Member] \| Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	$ 350.0
Manitoba Hydro PPA [Member] \| Manitoba Hydro [Member]
Transmission [Line Items]
Output Being Purchased (MW) \| MW	250

Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Consent Decree Wind Energy Generation Addition (MW) \| MW	200
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	$ 8
Expected Period to Incur Remediation Costs	4 years

Commitments, Guarantees and Contingencies - Other Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
ALLETE Clean Energy [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 21.0
U.S. Water Services [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.0
BNI Energy Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	47.5
BNI Energy Reclamation Liability [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.6
BNI Energy Reclamation Liability [Member] \| Surety Bonds [Member]
Guarantor Obligations [Line Items]
Collateral	49.9
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	6.1
ALLETE Properties Development and Maintenance Obligations [Member] \| Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	8.6
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	68.00%	70.00%
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	19.00%	33.00%
Annual Assessment	$ 0.6

Common Stock and Earnings Per Share - Summary of Common Stock (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of Common Stock [Line Items]
Balance, Shares	51,500,000	51,100,000
Received for Sale of Land Inventory, Equity			$ (8.0)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests			6.7
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value	$ 0.0	$ 13.5	$ 0.0
Common Stock [Member]
Summary of Common Stock [Line Items]
Balance, Shares	51,509,000	51,117,000	49,560,000	49,075,000
Balance, Equity	$ 1,428.5	$ 1,401.4	$ 1,295.3	$ 1,271.4
Employee Stock Purchase Plan, Shares	11,000	12,000	16,000
Employee Stock Purchase Plan, Equity	$ 0.8	$ 0.8	$ 0.9
Invest Direct, Shares	277,000	257,000	344,000
Invest Direct, Equity	$ 20.7	$ 19.0	$ 20.0
Options and Stock Awards, Shares	57,000	22,000	65,000
Options and Stock Awards, Equity	$ 2.1	$ 3.6	$ 3.7
Equity Issuance Program, Shares	0	1,000,000	130,000
Equity Issuance Program, Equity		$ 65.7	$ 8.0
Contributions to RSOP, Shares	47,000	50,000	60,000
Contributions to RSOP, Equity	$ 3.5	$ 3.5	$ 3.3
Received for Sale of Land Inventory, Shares			(130,000)
Received for Sale of Land Inventory, Equity			$ (8.0)
Acquisition of Non-Controlling Interest, Shares			0
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests			$ (4.0)
Employer Contributions to Pension - Shares	0	216,000	0
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value		$ 13.5
Equity Issuance Program Shares Authorized			13,600,000
Equity Issuance Program Shares Available for Issuance	2,900,000
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share	0	0	0
Pension Plan [Member]
Summary of Common Stock [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value	$ 0.0	$ 13.5	$ 0.0

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share - Basic [Abstract]
Net Income (Loss) Attributable to Parent	$ 61.1	$ 30.7	$ 31.3	$ 51.0	$ 41.4	$ 44.9	$ 36.9	$ 49.0	$ 44.3	$ 40.3	$ 24.8	$ 45.9	$ 174.1	$ 172.2	$ 155.3
Average Common Shares													51.3	50.8	49.3
Earnings Per Share	$ 1.19	$ 0.59	$ 0.61	$ 1.00	$ 0.81	$ 0.88	$ 0.73	$ 0.97	$ 0.89	$ 0.82	$ 0.50	$ 0.93	$ 3.39	$ 3.39	$ 3.15
Earnings Per Share - Diluted [Abstract]
Net Income (Loss) Available to Common Stockholders, Diluted													$ 174.1	$ 172.2	$ 155.3
Average Common Shares													51.5	51.0	49.5
Earnings Per Share	$ 1.18	$ 0.59	$ 0.61	$ 0.99	$ 0.81	$ 0.88	$ 0.72	$ 0.97	$ 0.89	$ 0.81	$ 0.50	$ 0.93	$ 3.38	$ 3.38	$ 3.14
Dilutive Securities (Shares)													0.2	0.2	0.2
Common Stock, Dividends, Per Share, Declared													$ 2.24	$ 2.14	$ 2.08

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Current Income Tax Expense [Abstract]

Federal

^[1]

$ 0.0

State

^[1]

0.3

0.4

Total Current Income Tax Expense

0.3

0.4

Deferred Income Tax Expense (Benefit) [Abstract]

Federal

^[2]

(26.2)

12.1

12.0

Federal - Remeasurement of Deferred Income Taxes

^[3]

0.0

(13.0)

0.0

State

11.0

15.8

8.1

Investment Tax Credit Amortization

(0.6)

(0.5)

(0.7)

Total Deferred Income Tax Expense (Benefit)

(15.8)

14.4

19.4

Total Income Tax Expense (Benefit)

$ (15.5)

$ 14.7

$ 19.8

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

21.00%

35.00%

[1]	For the years ended December 31, 2018, 2017 and 2016, 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 year ended December 31, 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, 2018

Dec. 31, 2017

Dec. 31, 2016

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

Income Before Non-Controlling Interest and Income Taxes

$ 158.6

$ 186.9

$ 175.6

Statutory Federal Income Tax Rate

21.00%

35.00%

Income Taxes Computed at Statutory Federal Rate

$ 33.3

$ 65.4

$ 61.5

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

State Income Taxes – Net of Federal Income Tax Benefit

8.9

10.5

5.6

Production Tax Credits

(45.0)

(45.1)

(41.5)

Regulatory Differences – Excess Deferred Tax Benefit

^[1]

(8.2)

1.2

1.4

Change in Fair Value of Contingent Consideration

(0.4)

0.0

(3.8)

Remeasurement of Deferred Income Taxes

^[2]

0.0

(13.0)

0.0

Other

(4.1)

(4.3)

(3.4)

Total Income Tax Expense (Benefit)

$ (15.5)

$ 14.7

$ 19.8

Effective Tax Rate

9.80%

7.90%

11.30%

[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, 2018

Dec. 31, 2017

Deferred Income Tax Assets [Abstract]

Employee Benefits and Compensation

$ 62.2

$ 65.9

Property Related

95.2

104.3

NOL Carryforwards

86.1

99.1

Tax Credit Carryforwards

349.8

294.3

Power Sales Agreements

27.5

35.0

Regulatory Liabilities

113.4

117.7

Other

25.1

33.3

Gross Deferred Income Tax Assets

759.3

749.6

Deferred Income Tax Asset Valuation Allowance

(66.5)

(60.0)

Total Deferred Income Tax Assets

692.8

689.6

Deferred Income Tax Liabilities [Abstract]

Property-Related

752.5

758.3

Regulatory Assets for Benefit Obligations

61.0

61.4

Unamortized Investment Tax Credits

32.2

32.8

Partnership Basis Differences

40.8

34.9

Regulatory Assets

29.9

32.0

Other

0.0

0.7

Total Deferred Income Tax Liabilities

916.4

920.1

Net Deferred Income Taxes

^[1]

$ 223.6

$ 230.5

[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, 2018

Dec. 31, 2017

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforwards

^[1]

$ 319.0

$ 375.2

Tax Credit Carryforwards

256.4

209.2

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]

305.8

289.9

Tax Credit Carryforwards

^[2]

27.4

25.6

Tax Credit Carryforwards, Valuation Allowance

$ 66.0

$ 59.5

[1]	Pre-tax amounts.
[2]	Net of a $66.0 million valuation allowance as of December 31, 2018 ($59.5 million as of December 31, 2017).

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 1.7	$ 2.0	$ 2.4
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	0.2
Reduction for Tax Positions Related to Prior Years	(0.2)	(0.1)	(0.3)
Lapse of Statute	(0.1)	(0.4)	(0.4)
Balance as of December 31	1.6	1.7	2.0
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.9
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 ($) $ in Millions		12 Months Ended
	Jan. 15, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value		$ 0.0	$ 13.5	$ 0.0
ESOP Compensation Expense		$ 11.4	$ 11.0	$ 9.2
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Common Stock Shares		0	216,000	0
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		$ 15.0	1.7	$ 6.3
Employer Contributions to Defined Benefit Pension Plans - Common Stock Value		$ 0.0	13.5	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 2019		$ 0.0
Pension Plan [Member] \| Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Pension Plans - Cash	$ 10.4
Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Employer Contributions in 2019		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, 2018

Dec. 31, 2017

Dec. 31, 2016

Change in Plan Assets [Roll Forward]

Non-Current Liabilities

$ (177.3)

$ (191.8)

Other Postretirement Benefits Plan [Member]

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

190.1

173.4

Service Cost

4.7

4.4

$ 3.9

Interest Cost

^[1]

7.1

7.7

7.4

Plan Amendments

(2.1)

(1.8)

Actuarial (Gain) Loss

(15.8)

15.5

Benefits Paid

(11.6)

(12.2)

Participant Contributions

3.6

3.1

Obligation, End of Year

176.0

190.1

173.4

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

171.0

154.3

Actual Return on Plan Assets

(9.6)

24.5

Employer Contribution

1.0

1.3

Defined Benefit Plan Contributions by Plan Participants, Excluding Key Employees

3.6

3.1

Benefits Paid

(11.7)

(12.2)

Fair Value, End of Year

154.3

171.0

154.3

Funded Status, End of Year

(21.7)

(19.1)

Non-Current Assets

0.4

3.0

Current Liabilities

(1.0)

(1.1)

Non-Current Liabilities

(21.1)

(21.0)

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Accumulated Benefit Obligation

713.7

745.4

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

793.2

743.3

Service Cost

11.0

10.2

8.1

Interest Cost

^[2]

29.6

32.5

33.2

Plan Amendments

(1.5)

0.0

Plan Curtailments

(6.9)

0.0

Actuarial (Gain) Loss

(53.0)

44.8

Benefits Paid

(49.5)

(51.0)

Participant Contributions

24.1

13.4

Obligation, End of Year

747.0

793.2

743.3

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

628.2

557.5

Actual Return on Plan Assets

(21.2)

91.6

Employer Contribution

^[3]

40.5

30.1

Benefits Paid

(49.5)

(51.0)

Fair Value, End of Year

598.0

628.2

$ 557.5

Funded Status, End of Year

(149.0)

(165.0)

Current Liabilities

(1.6)

(1.4)

Non-Current Liabilities

$ (147.4)

$ (163.6)

[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.
[3]	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, 2018	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Long-term Investments	$ 49.1	$ 53.1
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	20.4	16.5
Prior Service Credit	(4.6)	(4.6)
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	(1.3)	(2.6)
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	(21.7)	(19.1)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	(230.5)	(236.2)
Prior Service Credit	1.4	0.0
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	80.1	71.2
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	(149.0)	(165.0)
Trust for Benefit of Employees [Member] \| Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Long-term Investments	$ 18.3	$ 19.2

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Other Postretirement Benefits Plan [Member]

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

Service Cost

$ 4.7

$ 4.4

$ 3.9

Interest Cost

^[1]

7.1

7.7

7.4

Expected Return on Plan Assets

^[1]

(10.9)

(10.5)

(11.2)

Amortization of Loss

^[1]

0.8

0.3

0.2

Amortization of Prior Service Cost

^[1]

(2.1)

(2.0)

(2.9)

Net Pension Cost

(0.4)

(0.1)

(2.6)

Pension [Member]

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

Service Cost

11.0

10.2

8.1

Interest Cost

^[2]

29.6

32.5

33.2

Expected Return on Plan Assets

^[2]

(44.4)

(42.4)

(43.6)

Amortization of Loss

^[2]

11.4

9.9

9.5

Amortization of Prior Service Cost

^[2]

(0.1)

0.0

Net Pension Cost

$ 7.5

$ 10.2

$ 7.2

[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, 2018	Dec. 31, 2017
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ 4.7	$ 1.6
Prior Service Credit Arising During the Period	(2.1)	(1.8)
Amortization of Prior Service Cost	2.1	2.0
Amortization of Loss	(0.8)	(0.3)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	3.9	1.5
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	5.8	(4.3)
Amortization of Prior Service Cost	0.1	0.0
Prior Service Cost Arising During the Period	(1.6)	0.0
Amortization of Loss	(11.4)	(9.9)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$ (7.1)	$ (14.2)

Pension and Other Postretirement Benefit Plans - Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - Pension [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 747.0	$ 793.2
Accumulated Benefit Obligation	713.7	745.4
Fair Value of Plan Assets	$ 598.0	$ 628.2

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

Dec. 31, 2018

Dec. 31, 2017

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

Net Loss

^[1]

$ 25.0

$ 21.1

Prior Service Credit

(4.6)

Total Unrecognized Postretirement Health and Life Cost

$ 20.4

$ 16.5

[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, 2018

Dec. 31, 2017

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

Net Loss

^[1]

$ (25.0)

$ (21.1)

Prior Service Credit

4.6

Accumulated Net Periodic Benefit Cost in Excess of Contributions

(1.3)

(2.6)

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

$ (21.7)

$ (19.1)

[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, 2018 USD ($)
Pension [Member]
Estimated Future Benefit Payments [Abstract]
2019	$ 47.9
2020	47.4
2021	47.3
2022	47.1
2023	47.0
Years 2024 - 2028	231.1
Postretirement Health and Life [Member]
Estimated Future Benefit Payments [Abstract]
2019	9.7
2020	9.7
2021	9.8
2022	9.8
2023	9.7
Years 2024 - 2028	$ 51.1

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, 2018 USD ($)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 7.3
Prior Service Credit	(0.2)
Total Pension and Postretirement Health and Life Cost (Credit)	7.1
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	0.4
Prior Service Credit	(1.7)
Total Pension and Postretirement Health and Life Cost (Credit)	$ (1.3)

Pension and Other Postretirement Benefit Plans - Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.81%	4.53%	4.72%
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.96%	4.57%	4.73%
Pension [Member]
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	7.50%	7.50%	8.00%
Pension [Member] \| Minimum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.39%	3.81%
Rate of Compensation Increase	3.70%	3.70%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	3.70%	3.70%	3.70%
Pension [Member] \| Maximum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.53%	3.96%
Rate of Compensation Increase	4.10%	4.10%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	4.10%	4.30%	4.30%
Postretirement Health and Life [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.47%	3.86%
Health Care Trend Rates [Abstract]
Ultimate Trend Rate	4.50%	4.50%
Year Ultimate Trend Rate Effective	2038	2038
Postretirement Health and Life [Member] \| Minimum [Member]
Health Care Trend Rates [Abstract]
Trend Rate	5.00%	5.00%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	6.00%	6.00%	6.40%
Postretirement Health and Life [Member] \| Maximum [Member]
Health Care Trend Rates [Abstract]
Trend Rate	6.46%	6.73%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	7.50%	7.50%	8.00%

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, 2018 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	$ 2.0
Effect of One Percent Increase on Postretirement Health and Life Obligation	20.7
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.6)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (17.2)

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

Dec. 31, 2018

Dec. 31, 2017

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

32.00%

53.00%

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

60.00%

38.00%

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

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%

4.00%

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]

62.00%

64.00%

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]

34.00%

31.00%

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]

4.00%

5.00%

Plan Asset Target Allocations

^[2]

3.00%

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]

0.00%

[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, 2018	Dec. 31, 2017
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 33.2	$ 40.6
Actual Return on Plan Assets	2.8	7.1
Purchases, Sales, and Settlements – Net	(8.2)	(14.5)
Ending Balance	27.8	33.2
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	25.5	25.6
Actual Return on Plan Assets	0.7	1.7
Purchases, Sales, and Settlements – Net	(5.4)	(1.8)
Ending Balance	20.8	25.5
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	8.2	9.5
Actual Return on Plan Assets	0.9	2.6
Purchases, Sales, and Settlements – Net	(2.6)	(3.9)
Ending Balance	$ 6.5	$ 8.2

Employee Stock and Incentive Plans - Stock-Based Compensation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2018 shares
Non-Qualified Stock Options [Member]
Stock-based Compensation [Line Items]
Requisite Service Period (Years)	1 year
Vesting Period (Years)	3 years
Exercise Period (Years/Months)	10 years
Non-Qualified Stock Options [Member] \| Qualified Retirement, Death or Disability [Member]
Stock-based Compensation [Line Items]
Exercise Period (Years/Months)	3 years
Non-Qualified Stock Options [Member] \| Voluntary Termination or Involuntary Termination Without Cause [Member]
Stock-based Compensation [Line Items]
Exercise Period (Years/Months)	3 months
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)	0.9
Shares Available for Issuance	0.7

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 3.2	$ 3.1	$ 2.6
Income Tax Benefit	0.9	0.9	1.1
Capitalized Share-Based Compensation Costs	0.0	0.0	0.0
Performance Shares [Member]
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	2.3	2.1	1.8
Unrecognized Compensation Cost	$ 3.0
Weighted-Average Period for Recognition (Years/Months)	1 year 8 months
Restricted Stock Units [Member]
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 0.9	$ 1.0	$ 0.8
Unrecognized Compensation Cost	$ 1.0
Weighted-Average Period for Recognition (Years/Months)	1 year 7 months

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

1 Months Ended

12 Months Ended

Feb. 28, 2019

Jan. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Performance Shares [Member]

Stock-based Compensation [Line Items]

Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition

1 year 8 months

Number of Shares [Rollforward]

As of January 1

129,693

127,898

127,580

119,540

Granted

^[1]

66,557

50,729

57,189

Awarded

(58,293)

Unearned Grant Award

(40,801)

(42,126)

Forfeited

(6,469)

(9,610)

(7,023)

As of December 31

129,693

127,898

127,580

Performance Period (Years)

3 years

Weighted-Average Grant Date Fair Value [Abstract]

As of January 1

$ 66.12

$ 58.23

$ 52.56

$ 52.72

Granted

^[1]

76.42

62.90

52.43

Awarded

59.82

0.00

Unearned Grant Award

0.00

46.27

52.70

Forfeited

72.99

58.29

53.45

As of December 31

$ 66.12

$ 58.23

$ 52.56

Restricted Stock Units [Member]

Stock-based Compensation [Line Items]

Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition

1 year 7 months

Number of Shares [Rollforward]

As of January 1

49,771

55,248

54,728

57,694

Granted

^[2]

16,573

21,241

20,351

Awarded

(18,881)

(17,281)

(19,661)

Forfeited

(3,169)

(3,440)

(3,656)

As of December 31

49,771

55,248

54,728

Performance Period (Years)

3 years

Weighted-Average Grant Date Fair Value [Abstract]

As of January 1

$ 60.74

$ 56.18

$ 51.79

$ 49.86

Granted

^[2]

71.11

62.20

50.25

Awarded

55.78

49.72

44.33

Forfeited

64.92

56.00

52.87

As of December 31

$ 60.74

$ 56.18

$ 51.79

Subsequent Event [Member] | Performance Shares [Member]

Number of Shares [Rollforward]

Granted

31,843

Awarded

(73,532)

Performance Period (Years)

3 years

Granted, Grant Date Fair Value

$ 2.3

Awarded, Grant Date Fair Value

$ 3.9

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

Number of Shares [Rollforward]

Granted

12,924

Awarded

(14,307)

Granted, Grant Date Fair Value

$ 1.0

Awarded, Grant Date Fair Value

$ 0.7

[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, 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, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Segment Reporting Information [Line Items]

Revenues

$ 448.3

$ 348.0

$ 344.1

$ 358.2

$ 337.9

$ 362.5

$ 353.3

$ 365.6

$ 341.5

$ 349.6

$ 314.8

$ 333.8

$ 1,498.6

$ 1,419.3

$ 1,339.7

Net Income (Loss) Attributable to Parent

61.1

$ 30.7

$ 31.3

$ 51.0

41.4

$ 44.9

$ 36.9

$ 49.0

$ 44.3

$ 40.3

$ 24.8

$ 45.9

174.1

172.2

155.3

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

^[1]

0.0

13.0

0.0

Depreciation, Depletion and Amortization

205.6

177.5

195.8

Operating Expenses – Other

(2.0)

(0.7)

(10.3)

Interest Expense

67.9

67.8

70.3

Equity Earnings in ATC

17.5

22.5

18.5

Income Tax Expense (Benefit)

(15.5)

14.7

19.8

Assets

5,165.0

5,080.0

5,165.0

5,080.0

Property, Plant and Equipment, Additions

$ 318.6

266.5

Regulated Operations [Member]

Segment Reporting Information [Line Items]

Number of Operating Segments

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

0.0

Depreciation, Depletion and Amortization

$ 158.0

132.6

154.3

Interest Expense

^[2]

60.2

57.0

52.1

Equity Earnings in ATC

17.5

22.5

18.5

Income Tax Expense (Benefit)

(15.5)

27.2

5.9

Property, Plant and Equipment, Additions

211.9

177.1

Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenues

1,059.5

1,063.8

1,000.7

Net Income (Loss) Attributable to Parent

^[3],[4]

131.0

128.4

135.5

Assets

$ 3,952.5

3,886.6

$ 3,952.5

3,886.6

Corporate and Other [Member]

Segment Reporting Information [Line Items]

Number of Operating Segments

Land in Minnesota (Acres) | a

4,000

Revenues

$ 107.1

123.2

121.0

Net Income (Loss) Attributable to Parent

^[3],[4],[5]

6.2

(8.4)

4.9

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

(19.8)

Depreciation, Depletion and Amortization

13.0

11.7

10.3

Operating Expenses – Other

^[6]

(2.0)

(0.7)

(13.6)

Interest Expense

^[2]

7.3

10.3

14.5

Income Tax Expense (Benefit)

0.0

9.5

4.4

Assets

$ 310.1

300.5

310.1

300.5

Property, Plant and Equipment, Additions

12.0

28.9

Consolidation, Eliminations [Member]

Segment Reporting Information [Line Items]

Interest Expense

^[2]

(4.7)

(5.3)

(3.8)

ALLETE Clean Energy [Member]

Segment Reporting Information [Line Items]

Revenues

159.9

80.5

Net Income (Loss) Attributable to Parent

^[3],[4],[7]

33.7

41.5

13.4

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

23.6

Depreciation, Depletion and Amortization

24.4

23.4

22.3

Operating Expenses – Other

^[6]

0.0

3.3

Interest Expense

^[2]

3.6

4.2

5.8

Income Tax Expense (Benefit)

(1.0)

(14.2)

8.1

Assets

606.6

600.5

606.6

600.5

Property, Plant and Equipment, Additions

89.7

56.1

U.S. Water Services [Member]

Segment Reporting Information [Line Items]

Revenues

172.1

151.8

137.5

Net Income (Loss) Attributable to Parent

^[3],[4]

3.2

10.7

1.5

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

9.2

Depreciation, Depletion and Amortization

10.2

9.8

8.9

Interest Expense

^[2]

1.5

1.6

1.7

Income Tax Expense (Benefit)

1.0

(7.8)

1.4

Assets

$ 295.8

$ 292.4

295.8

292.4

Property, Plant and Equipment, Additions

5.0

4.4

Residential [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

139.7

127.4

127.9

Commercial [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

147.9

139.8

139.5

Municipal [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

54.9

57.9

67.6

Industrial [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

469.5

470.5

416.0

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

170.3

161.8

175.1

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

3.0

5.5

7.5

Other [Member] | Regulated Operations [Member]

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

74.2

100.9

67.1

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

55.2

56.9

58.2

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

Segment Reporting Information [Line Items]

Sale of Wind Energy Facility

^[8]

81.1

0.0

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

Segment Reporting Information [Line Items]

Revenue, Other Than Customer Revenue

^[8]

23.6

22.3

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

100.3

95.8

93.9

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

38.3

36.2

30.4

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

33.5

19.8

13.2

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

85.5

89.3

73.7

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

Segment Reporting Information [Line Items]

Revenue from Contract with Customer, Excluding Assessed Tax

^[8]

$ 21.6

33.9

47.3

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

8.8

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

Segment Reporting Information [Line Items]

Net Income (Loss) Attributable to Parent

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

(15.0)

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)

$ 8.8

[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]	Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation.
[4]	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.)
[5]	Net income in 2017 included a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of tits November 2016 order on the allocation of North Dakota investment tax credits. Net income in 2016 included an $8.8 million after-tax adverse impact for the regulatory outcome of the November 2016 order.
[6]	See Note 1. Operations and Significant Accounting Policies.
[7]	Net income in 2018 includes the recognition of profit for the sale of a wind energy facility to Montana-Dakota Utilities.
[8]	With the adoption of new revenue recognition guidance, the Company has enhanced the presentation of business segment Operating Revenue. (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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Abstract]
Operating Revenue	$ 448.3	$ 348.0	$ 344.1	$ 358.2	$ 337.9	$ 362.5	$ 353.3	$ 365.6	$ 341.5	$ 349.6	$ 314.8	$ 333.8	$ 1,498.6	$ 1,419.3	$ 1,339.7
Operating Income	64.0	43.3	36.5	57.4	32.3	68.0	54.0	71.6	59.4	51.8	40.6	65.2	201.2	225.9	217.0
Net Income Attributable to ALLETE	$ 61.1	$ 30.7	$ 31.3	$ 51.0	$ 41.4	$ 44.9	$ 36.9	$ 49.0	$ 44.3	$ 40.3	$ 24.8	$ 45.9	$ 174.1	$ 172.2	$ 155.3
Basic Earnings Per Share of Common Stock	$ 1.19	$ 0.59	$ 0.61	$ 1.00	$ 0.81	$ 0.88	$ 0.73	$ 0.97	$ 0.89	$ 0.82	$ 0.50	$ 0.93	$ 3.39	$ 3.39	$ 3.15
Diluted Earnings Per Share of Common Stock	$ 1.18	$ 0.59	$ 0.61	$ 0.99	$ 0.81	$ 0.88	$ 0.72	$ 0.97	$ 0.89	$ 0.81	$ 0.50	$ 0.93	$ 3.38	$ 3.38	$ 3.14

- 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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-Publisher FASB
-Name Accounting Standards Codification
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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.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
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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

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Trade Accounts Receivable [Member]

Valuation and Qualifying Accounts and Reserves [Roll Forward]

Balance at Beginning of Period

$ 2.1

$ 3.1

$ 1.0

Additions, Charged to Income

0.9

0.8

4.1

Additions, Other Charges

0.0

Deductions from Reserves

^[1]

1.3

1.8

2.0

Balance at End of Period

1.7

2.1

3.1

Finance Receivables – Long-Term [Member]

Valuation and Qualifying Accounts and Reserves [Roll Forward]

Balance at Beginning of Period

0.0

0.6

Additions, Charged to Income

0.0

Additions, Other Charges

0.0

Deductions from Reserves

^[1]

0.0

0.6

Balance at End of Period

0.0

Deferred Tax Assets [Member]

Valuation and Qualifying Accounts and Reserves [Roll Forward]

Balance at Beginning of Period

60.0

43.0

31.6

Additions, Charged to Income

6.5

17.0

11.4

Additions, Other Charges

0.0

Deductions from Reserves

^[1]

0.0

Balance at End of Period

$ 66.5

$ 60.0

$ 43.0

[1]	Includes uncollectible accounts written-off.

Operations and Significant Accounting Policies - Subsequent Events (Details) - Subsequent Event [Member] $ in Millions	Feb. 08, 2019 USD ($)
Subsequent Event [Line Items]
Cash Purchase Price on the Sale of U.S. Water Services	$ 270
Estimated Gain on the Sale of U.S. Water Services	$ 10

Short-Term and Long-Term Debt - Financial Covenants (Details)	Dec. 31, 2018
Financial Covenants [Abstract]
Allowed Indebtedness to Total Capitalization Ratio	0.65
Actual Indebtedness to Total Capitalization Ratio	0.41

Commitments, Guarantees and Contingencies - Legal Proceedings (Details) - U.S. Water Services [Member] - U.S. Water Services Patent Defense Litigation [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Legal Proceedings [Line Items]
Patents Infringed	2
Addition to Intangible Assets for Patent Defense Costs	$ 2.6

Operations and Significant Accounting Policies - Reclassification of Prior Income Statement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Operating Revenue – Utility [Member]
Schedule of Prior Period Reclassification Adjustments [Line Items]
Prior Period Reclassification Adjustment	$ 1,063.8	$ 1,000.7
Operating Revenue – Non-utility [Member]
Schedule of Prior Period Reclassification Adjustments [Line Items]
Prior Period Reclassification Adjustment	331.9	316.7
Other Operating Revenue - Non-utility [Member]
Schedule of Prior Period Reclassification Adjustments [Line Items]
Prior Period Reclassification Adjustment	$ 23.6	$ 22.3

Acquisitions (Details)	12 Months Ended
Acquisitions (Details)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Reason for Business Acquisitions	The following acquisitions are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.	The following acquisitions are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.	The following acquisitions are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.