Goodwill and Intangible Assets – Net

3,822.4

3,741.2

Regulatory Assets

384.7

330.1

Investment in ATC

118.7

135.6

Other Investments

53.1

55.6

225.9

213.4

Long-Term Debt Due Within One Year

107.7

106.5

Total Assets

^[1]

5,080.0

4,876.9

Current Liabilities [Abstract]

Accounts Payable

136.3

74.0

Accrued Taxes

50.0

46.5

Accrued Interest

17.6

64.1

187.7

Total Current Liabilities

83.2

73.7

351.2

399.5

Long-Term Debt

1,439.2

1,370.4

Deferred Income Taxes

230.5

554.6

Regulatory Liabilities

532.0

125.8

Defined Benefit Pension and Other Postretirement Benefit Plans

191.8

210.9

Other Non-Current Liabilities

267.1

322.7

Total Liabilities

3,011.8

2,983.9

Commitments, Guarantees and Contingencies (Note 11)

Shareholders' Equity [Abstract]

Common Stock Without Par Value, 80.0 Shares Authorized, 51.1 and 49.6 Shares Issued and Outstanding

1,401.4

1,295.3

Accumulated Other Comprehensive Loss

(22.6)

(28.2)

Retained Earnings

689.4

625.9

Total Shareholders' Equity

2,068.2

1,893.0

Total Liabilities and Shareholders' Equity

$ 5,080.0

$ 4,876.9

[1]	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 2.1	$ 3.1
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	51.1	49.6
Common Stock, Shares Issued	51.1	49.6

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Revenue [Abstract]
Utility	$ 1,063.8	$ 1,000.7	$ 991.2
Non-utility	355.5	339.0	495.2
Total Operating Revenue	1,419.3	1,339.7	1,486.4
Operating Expenses [Abstract]
Fuel, Purchased Power and Gas - Utility	396.9	339.9	336.0
Transmission Services - Utility	71.2	65.2	54.1
Cost of Sales - Non-utility	147.8	137.7	294.4
Operating and Maintenance	339.9	334.1	333.5
Depreciation and Amortization	177.5	195.8	170.0
Taxes Other Than Income Taxes	56.9	53.8	51.4
Other	(0.7)	(10.3)	36.3
Total Operating Expenses	1,189.5	1,116.2	1,275.7
Operating Income	229.8	223.5	210.7
Other Income (Expense) [Abstract]
Interest Expense	(67.8)	(70.3)	(64.9)
Equity Earnings in ATC	22.5	18.5	16.3
Other	2.4	3.9	4.7
Total Other Expense	(42.9)	(47.9)	(43.9)
Income Before Non-Controlling Interest and Income Taxes	186.9	175.6	166.8
Income Tax Expense	14.7	19.8	25.3
Net Income	172.2	155.8	141.5
Less: Non-Controlling Interest in Subsidiaries	0.0	0.5	0.4
Net Income Attributable to ALLETE	$ 172.2	$ 155.3	$ 141.1
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	50.8	49.3	48.3
Diluted (Shares)	51.0	49.5	48.4
Basic Earnings Per Share of Common Stock	$ 3.39	$ 3.15	$ 2.92
Diluted Earnings Per Share of Common Stock	3.38	3.14	2.92
Dividends Per Share of Common Stock	$ 2.14	$ 2.08	$ 2.02

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Comprehensive Income [Abstract]
Net Income	$ 172.2	$ 155.8	$ 141.5
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities - Net of Income Tax Expense (Benefit) of $0.7, $(0.2) and $(0.3)	0.9	(0.2)	(0.5)
Unrealized Gain on Derivatives - Net of Income Tax Expense of $–, $– and $0.1	0.0	0.0	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Tax Expense (Benefit) of $2.2, $(2.4) and $(2.2)	4.7	(3.5)	(3.0)
Total Other Comprehensive Income (Loss)	5.6	(3.7)	(3.4)
Total Comprehensive Income	177.8	152.1	138.1
Less: Non-Controlling Interest in Subsidiaries	0.0	0.5	0.4
Total Comprehensive Income Attributable to ALLETE	$ 177.8	$ 151.6	$ 137.7

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Unrealized Gain (Loss) on Securities, Income Tax Expense (Benefit)	$ 0.7	$ (0.2)	$ (0.3)
Unrealized Gain on Derivatives, Income Tax Expense	0.0	0.0	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Tax Expense (Benefit)	$ 2.2	$ (2.4)	$ (2.2)

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Operating Activities

Net Income

$ 172.2

$ 155.8

$ 141.5

Allowance for Funds Used During Construction – Equity

(1.2)

(2.1)

(3.3)

Income from Equity Investments – Net of Dividends

(3.2)

(5.7)

(1.8)

0.0

36.3

Change in Fair Value of Contingent Consideration

0.0

3.3

^[1]

0.0

(0.7)

(13.6)

0.0

Increase (Decrease) in Deferred Fuel Costs

19.5

0.0

Gain on Sales of Investments and Property, Plant and Equipment

0.4

(6.0)

(0.2)

Depreciation Expense

171.9

190.6

165.9

Amortization of Power Sales Agreements

(23.6)

(22.3)

(23.2)

Amortization of Other Intangible Assets and Other Assets

10.2

10.3

5.6

Deferred Income Tax Expense

14.4

19.4

25.1

Share-Based Compensation Expense

6.6

5.1

11.6

Defined Benefit Pension and Other Postretirement Benefit Expense

10.1

4.6

15.4

Bad Debt Expense

0.8

4.1

1.6

Provision for Interim Rate Refund

32.3

0.0

Changes in Operating Assets and Liabilities

Accounts Receivable

(8.0)

(4.7)

1.1

Inventories

11.9

13.3

(22.1)

Prepayments and Other

(5.3)

(6.9)

3.7

Accounts Payable

(7.5)

6.5

(19.3)

Other Current Liabilities

1.8

(13.8)

5.1

Cash Contributions to Defined Benefit Pension Plans

(1.7)

(6.3)

0.0

Changes in Regulatory and Other Non-Current Assets

33.7

(10.7)

0.6

Changes in Regulatory and Other Non-Current Liabilities

(31.7)

11.1

(3.5)

Cash from Operating Activities

402.9

332.0

340.1

Investing Activities

Proceeds from Sale of Available-for-sale Securities

10.1

9.0

1.7

Payments for Purchase of Available-for-sale Securities

(8.6)

(9.4)

(2.3)

Acquisitions of Subsidiaries – Net of Cash Acquired

(18.5)

(5.9)

(333.3)

Investment in ATC

(7.8)

(5.4)

(1.6)

Changes to Other Investments

3.0

4.4

3.1

Additions to Property, Plant and Equipment

(208.5)

(265.6)

(286.8)

Proceeds from Sale of Property, Plant and Equipment

1.3

0.7

0.4

Changes in Restricted Cash

0.0

(4.0)

0.0

Cash for Investing Activities

(229.0)

(276.2)

(618.8)

Financing Activities

Proceeds from Issuance of Common Stock

86.0

30.9

161.2

Proceeds from Issuance of Long-Term Debt

131.5

4.8

324.5

Changes in Restricted Cash

(0.4)

7.0

8.5

Changes in Notes Payable

0.0

(1.6)

(2.1)

Repayments of Long-Term Debt

(189.6)

(54.8)

(160.2)

Acquisition of Non-Controlling Interest

0.0

(8.0)

0.0

Payment for Contingent Consideration Liability, Financing Activities

(19.7)

(0.9)

0.0

Dividends on Common Stock

(108.7)

(102.7)

(97.9)

Other Financing Activities

(1.6)

0.0

(4.1)

Cash from (for) Financing Activities

(102.5)

(125.3)

229.9

Change in Cash and Cash Equivalents

71.4

(69.5)

(48.8)

Cash and Cash Equivalents at Beginning of Period

27.5

97.0

145.8

Cash and Cash Equivalents at End of Period

$ 98.9

$ 27.5

$ 97.0

[1]

The facts and circumstances that led to an impairment of ALLETE Clean Energy’s goodwill primarily relate to lower estimated energy prices in periods not under PSAs. Impairment Charge is included in Operating Expenses – Other on the Consolidated Statement of Income. (See Note 1. Operations and Significant Accounting Policies.) ALLETE Clean Energy’s goodwill was primarily related to the acquisition of Storm Lake II in 2014.

Consolidated Statement of Equity - USD ($) $ in Millions	Total	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Unearned ESOP Shares [Member]	Common Stock [Member]	Non-Controlling Interest in Subsidiaries [Member]
Beginning Balance at Dec. 31, 2014	$ 1,611.2	$ 530.1	$ (21.1)	$ (7.2)	$ 1,107.6	$ 1.8
Comprehensive Income
Net Income	141.5	141.1				0.4
Other Comprehensive Income – Net of Tax
Unrealized Gain (Loss) on Securities	(0.5)		(0.5)
Unrealized Gain on Derivatives	0.1		0.1
Defined Benefit Pension and Other Postretirement Plans	(3.0)		(3.0)
Total Comprehensive Income	138.1
Common Stock Issued	163.8				163.8
Dividends Declared	(97.9)	(97.9)
ESOP Shares Earned	7.2			7.2
Ending Balance at Dec. 31, 2015	1,822.4	573.3	(24.5)	0.0	1,271.4	2.2
Comprehensive Income
Net Income	155.8	155.3				0.5
Other Comprehensive Income – Net of Tax
Unrealized Gain (Loss) on Securities	(0.2)		(0.2)
Unrealized Gain on Derivatives	0.0
Defined Benefit Pension and Other Postretirement Plans	(3.5)		(3.5)
Total Comprehensive Income	152.1
Common Stock Issued	35.9				35.9
Dividends Declared	(102.7)	(102.7)
Common Stock Retired	(8.0)
Acquisition of Non-Controlling Interest	(6.7)				(4.0)	(2.7)
Ending Balance at Dec. 31, 2016	1,893.0	625.9	(28.2)	0.0	1,295.3	0.0
Comprehensive Income
Net Income	172.2	172.2				0.0
Other Comprehensive Income – Net of Tax
Unrealized Gain (Loss) on Securities	0.9		0.9
Unrealized Gain on Derivatives	0.0
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)	$ 0.0	$ 1,401.4	$ 0.0

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

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

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

Principles of Consolidation. Our Consolidated Financial Statements include the accounts of ALLETE 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 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 535 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, ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 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 2017, 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 related to the real estate assets of ALLETE Properties is to sell individual parcels over time, but incorporates the possibility of a bulk sale of our entire real estate portfolio. Proceeds from a bulk sale would be strategically deployed to support growth in ALLETE Clean Energy and U.S. Water Services, collectively our energy infrastructure and related services businesses. ALLETE Properties will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions. (See Note 8. Investments.)

Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flow Information.



Consolidated Statement of Cash Flows
Year Ended December 31	2017		2016		2015
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$64.5		$68.2		$59.0
Cash Paid During the Period for Income Taxes		$0.4		$0.5		$0.4
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	$67.2		$(22.0)		$(40.6)
Capitalized Asset Retirement Costs	$(15.6)			$3.7	$12.4
Camp Ripley Solar Financing	—		$15.0		—
AFUDC–Equity		$1.2		$2.1		$3.3
ALLETE Common Stock Contributed to Pension Plans		$13.5	—		—
Contingent Consideration	—		—			$35.7
ALLETE Common Stock Received for Land Inventory	—			$8.0	—
Long-Term Finance Receivable for Land Inventory	—			$12.0	—

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



Accounts Receivable
As of December 31	2017		2016
Millions
Trade Accounts Receivable
Billed		$112.6		$106.5
Unbilled	24.6		19.1
Less: Allowance for Doubtful Accounts	2.1		3.1
Total Accounts Receivable		$135.1		$122.5

Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to nine Large Power Customers. Receivables from these customers totaled $13.8 million as of December 31, 2017 ($9.5 million as of December 31, 2016). 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 2017 (8 percent in 2016 and in 2015).

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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Available-for-Sale Securities. Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as share price trends and the impact of overall market conditions. (See New Accounting Pronouncements and Note 8. Investments.)

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



Inventories – Net
As of December 31	2017			2016
Millions
Fuel (a)		$34.8			$43.9
Materials and Supplies	46.5			48.7
Raw Materials	2.8			2.9
Work in Progress	4.2			1.0
Finished Goods	8.3			8.6
Reserve for Obsolescence	(0.7		)	(0.9		)
Total Inventories – Net		$95.9			$104.2


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



Prepayments and Other Current Assets
As of December 31	2017		2016
Millions
Deferred Fuel Adjustment Clause (a)	—			$18.6
Restricted Cash (b)		$2.6	2.2
Other	35.0		19.5
Total Prepayments and Other Current Assets		$37.6		$40.3


(a)	At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017.


(b)	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and collateral deposits required for U.S. Water Services’ standby letters of credit.

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.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Property, Plant and Equipment (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 2015, Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to operate on natural gas which were actions included in Minnesota Power’s MPUC-approved 2013 IRP. In a July 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The 2015 IRP contains steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in September 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. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018. 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.

Real Estate Assets. In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In 2015, the Company reevaluated its strategy related to the real estate assets of ALLETE Properties in response to market conditions and transaction activity. The revised strategy incorporated the possibility of a bulk sale of its entire portfolio. Proceeds from a bulk sale would be strategically deployed to support growth in ALLETE Clean Energy and U.S. Water Services, collectively our Energy Infrastructure and Related Services businesses. ALLETE Properties also continues to pursue sales of individual parcels over time. ALLETE Properties will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.

In connection with implementing the revised strategy, management evaluated its impairment analysis for its real estate assets using updated assumptions to determine estimated future net cash flows on an undiscounted basis. Estimated fair values were based upon current market data and pricing for individual parcels. Our impairment analysis incorporates a probability-weighted approach considering the alternative courses of sales noted above.

Based on the results of the 2015 undiscounted cash flow analysis, the undiscounted future net cash flows were not adequate to recover the carrying value of the real estate assets leading to an adjustment of carrying value to estimated fair value. Estimated fair value was derived using Level 3 inputs, including current market interest in the property for a bulk sale of its entire portfolio, and discounted cash flow analysis of estimated selling price for sales over time. As a result, a non-cash impairment charge of $36.3 million was recorded in 2015 to reduce the carrying value of the real estate to its estimated fair value.

In 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 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.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

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 2017, 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 2017 indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and therefore no impairment existed (none in 2016 or in 2015). The fair value of the reporting unit was determined using a discounted cash flow model, using significant assumptions which included a discount rate of 10.75 percent, cash flow forecasts through 2022, annual revenue growth rates ranging from 7 percent to 9 percent, excluding 13 percent of revenue growth in 2018 related to the year over year impact of the acquisition of Tonka Water, and a terminal growth rate of 4.0 percent. Forecasted annual revenue growth assumes an increase in market share and growth in the industry.

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 1 year to approximately 20 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 2017 indicated that the estimated fair value of trademarks and trade names exceeded the asset carrying values. As a result, no impairment existed in 2017 (none in 2016 or in 2015).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Non-Current Assets
As of December 31	2017		2016
Millions
Contract Payment (a)		$27.5		$29.6
Finance Receivable (b)	11.0		11.5
Restricted Cash (c)	8.6		8.6
Other	60.6		56.8
Total Other Non-Current Assets		$107.7		$106.5


(a)	Contract Payment includes a payment made to Cliffs as part of a long-term PSA between Minnesota Power and Silver Bay Power. The contract payment is being amortized over the term of the PSA. (See Note 11. Commitments, Guarantees and Contingencies.)

(b)

In 2016, ALLETE Properties sold its Ormond Crossings project and Lake Swamp wetland mitigation bank for consideration of approximately $21 million. The consideration included a down payment in the form of 0.1 million shares of ALLETE common stock with a value of $8.0 million. The remaining purchase price will be paid under the terms of a finance receivable due over a five-year period which bears interest at market rates and is collateralized by the property sold.


(c)	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.



Other Current Liabilities
As of December 31	2017		2016
Millions
PSAs		$24.5		$24.6
Other	58.7		49.1
Total Other Current Liabilities		$83.2		$73.7



Other Non-Current Liabilities
As of December 31	2017		2016
Millions
Asset Retirement Obligation		$122.7		$136.6
PSAs	89.5		113.8
Contingent Consideration (a)	5.4		25.0
Other	49.5		47.3
Total Other Non-Current Liabilities		$267.1		$322.7


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 6. Acquisitions and 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.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition.

Regulated Operations utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for services provided but not yet billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission, renewable, and environmental improvement expenditures. Previously, fuel and purchased power expense was deferred to match the period in which the revenue for fuel and purchased power expense was billed to customers with the deferred fuel costs recognized as a regulatory asset. 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 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 a result of the MPUC hearing, fuel and purchased power costs above or below the base levels in rate schedules are no longer deferred.

Revenue from cost recovery riders (transmission, renewable and environmental improvement) is accounted for in accordance with GAAP for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory authority, the order allows automatic adjustment of future rates, the amount of the 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. Revenue recognized using the alternative revenue program guidance is included in Operating Revenue – Utility on the Consolidated Statement of Income and Regulatory Assets on the Consolidated Balance Sheet until it is subsequently collected from customers.

Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue – Utility and net purchases in Fuel, Purchased Power and Gas – Utility expense on the Consolidated Statement of Income.

ALLETE Clean Energy recognizes revenue from the sale of energy from PSAs under various durations. Revenue is recognized when delivered to an agreed upon point or production is curtailed at the request of its customers at specified prices. As part of its acquisitions of wind energy facilities, ALLETE Clean Energy has assumed various PSAs that were above or below estimated market prices at the time of acquisition and amortizes the resulting differences between contract prices and estimated market prices to Operating Revenue – Non-utility on the Consolidated Statement of Income. In 2017, we recognized $23.6 million of non-cash revenue amortization relating to the difference between contract prices and estimated market prices as an increase in Operating Revenue – Non-utility ($22.3 million in 2016; $23.2 million in 2015). Revenue from the construction and sale of wind energy facilities to others will be recognized at a point in time, or over time, as performance obligations are satisfied based on the terms of each specific agreement.

U.S. Water Services recognizes revenue from the sale of products when the earnings process is complete. This generally occurs when products are shipped to the customer in accordance with the contract or purchase order, ownership and risk of loss have passed to the customer, collectibility is reasonably assured, and pricing is fixed and determinable. Revenue from services is recognized as the services are performed.

Corporate and Other

BNI Energy recognizes coal sales when delivered at the cost of production plus a specified profit per ton of coal delivered.

ALLETE Properties records full profit recognition on sales of real estate upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. Certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Operating Expenses – Other
Year Ended December 31	2017	2016			2015
Millions
Impairment of Real Estate (a)	—	—				$36.3
Impairment of Goodwill (b)	—		$3.3		—
Change in Fair Value of Contingent Consideration (c)	$(0.7)	(13.6		)	—
Total Operating Expenses – Other	$(0.7)	$(10.3)				$36.3


(a)	See Impairment of Long-Lived Assets.


(b)	See Goodwill and Intangible Assets.


(c)	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.)

Tax Cuts and Jobs Act of 2017. On December 22, 2017, the TCJA was enacted into law. The TCJA has significantly changed the U.S. Internal Revenue Code (IRC) and the taxation of corporations. The more significant provisions that impact our Company include a reduction in the corporate federal income tax rate from 35 percent to 21 percent, and provisions related to our regulated utilities which generally allow for the continued deductibility of interest expense, the elimination of full expensing for property acquired after September 27, 2017, and the continuation of normalization requirements for accelerated tax depreciation taken by regulated utilities. The TCJA allows for full expensing for property and imposes an interest expense limitation on non‑regulated operations. The interest expense limitation is not expected to have a material impact on the Company.

Under ASC 740, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. ASC 740 requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, as of the date of enactment, the Company’s deferred income tax assets and liabilities were remeasured based upon the new tax rate. For our Regulated Operations segment, the change in deferred income taxes was recorded as regulatory assets, regulatory liabilities and a change to our investment in ATC. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the IRC over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. The decrease in our investment in ATC is expected to be amortized into earnings over time. For our ALLETE Clean Energy and U.S. Water Services segments as well as our Corporate and Other businesses, the change in deferred income taxes is recorded in income tax expense on the Consolidated Statement of Income.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118) which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete, and provides for up to a one year period in which to complete the required analyses and accounting (the measurement period). SAB 118 describes three scenarios associated with a company’s status of accounting for the TCJA: (1) a company is complete with its accounting for certain effects, (2) a company is able to determine a reasonable estimate for certain effects and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Income Taxes (Continued)

The Company has made a provisional estimate for the measurement and accounting of the effects of the TCJA, which have been reflected in the Consolidated Financial Statements as of December 31, 2017. The measurement and accounting of the effects of the TCJA resulted in a decrease to Income Tax Expense of $13.0 million for the year ended December 31, 2017, as well as a decrease to Deferred Income Taxes of $353.6 million, a decrease to Investment in ATC of $27.9 million, an increase to Regulatory Assets of $80.9 million and an increase to Regulatory Liabilities of $393.6 million as of December 31, 2017. The provisional amounts incorporate assumptions made based upon the Company’s current interpretation of the TCJA, and may change as the Company receives additional clarification and implementation guidance. Any adjustments recorded to the provisional amounts in 2018 will be included in income from operations as an adjustment to income tax expense.

As provided for under SAB 118, the Company has not estimated the impact for items for which it cannot predict, such as guidance that has not yet been provided, or for which federal or state regulatory treatment is still uncertain. The determination of the impact of the income tax effects of these types of items will occur when more information is available to the Company.

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 the 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

Simplifying the Measurement of Inventory. In 2015, the FASB issued an accounting standards update which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance was adopted in the first quarter of 2017 and did not have a material impact on our Consolidated Financial Statements.

Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued guidance to simplify the accounting for share-based payment transactions by requiring all excess tax benefits and deficiencies to be recognized in income tax expense or benefit in earnings, thus eliminating the requirement to classify the excess tax benefit and deficiencies as additional paid-in capital. Under the new guidance, an entity makes an accounting policy election to either estimate the expected forfeiture awards or account for forfeitures as they occur. This accounting guidance was adopted in the first quarter of 2017. The adoption of this guidance is expected to result in a less than $1 million impact to income tax expense (benefit) annually.

Clarifying the Definition of a Business. In January 2017, the FASB issued clarifying guidance on the definition of a business and provided additional guidance to assist with evaluating whether transactions are to be accounted for as an acquisition or disposal of a group of assets or a business. The clarifying guidance will also impact other areas including the accounting for goodwill and consolidation. This accounting guidance was adopted in the first quarter of 2017 and did not have an impact on our Consolidated Financial Statements.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Stock Compensation: Scope of Modification Accounting. In May 2017, the FASB issued additional clarifying guidance regarding circumstances where changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting under ASC 718. The guidance provides specific situations that would be excluded from effects of a modification including if the fair value, vesting conditions, and classification are the same before and after modification. The amendments in this update will be applied prospectively to awards modified on or after adoption. This accounting guidance was adopted by the Company in the second quarter of 2017 and did not have an impact on our Consolidated Financial Statements.

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.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued guidance to improve the presentation of net periodic pension and postretirement benefit costs. Under the revised guidance of ASC 715, an entity shall 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. The standard will be applied retrospectively for income statement presentation, and prospectively for capitalization of service cost components. We do not expect there to be a material impact on the Consolidated Financial Statements with the adoption of the updated guidance which is effective for the Company beginning in the first quarter of 2018.

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 in exchange for those goods or services. The guidance also 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 are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. As of December 31, 2017, the Company has reviewed all of its revenue streams and contracts for its regulated, energy infrastructure and related services, and corporate and other businesses, completing the evaluations of the impact of this new guidance. Based on these evaluations, the Company has determined the new guidance does not materially alter the amount or timing of revenue recognition from the current methodology nor does it have a material transition adjustment upon adoption. Additionally, management does not expect the recognition of any assets from the costs to obtain a contract. Management continues to draft and refine the additional disclosures needed to meet the requirements of the new standard following adoption. The Company will adopt and implement the new guidance on a modified retrospective basis which requires application of standards to all contracts with customers effective January 1, 2018, with the cumulative impact on contracts with performance obligations not yet satisfied as of December 31, 2017, recognized as an adjustment to Retained Earnings on the Consolidated Balance Sheet.

Leases. In February 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, 2017, ALLETE expects to make $79.9 million in minimum lease payments due in future years (undiscounted). The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. We are currently evaluating the impact of the revised lease guidance on our Consolidated Financial Statements.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Financial Instruments. In January 2016, the FASB issued an accounting standard update which requires entities to measure their 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 updated guidance is effective for the Company beginning in the first quarter of 2018 and will result in a cumulative-effect adjustment to Retained Earnings on the Consolidated Balance Sheet in the fiscal year of adoption. We have performed a preliminary evaluation of the impact of this update, and based on that evaluation, we do not expect the adoption of the update to have a material impact on our Consolidated Financial Statements.

Classification of Certain Cash Receipts and Cash Payments. In August 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. This accounting guidance is effective for the Company beginning in the first quarter of 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.

Statement of Cash Flows: Restricted Cash. In November 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 accounting guidance is effective for the Company beginning in the first quarter of 2018 and will be applied retrospectively to all periods presented. The guidance will result in changes to the Company’s Consolidated Statement of Cash Flows such that restricted cash amounts will be included in the beginning-of-period and end‑of‑period cash and cash equivalents totals when adopted for our fiscal year beginning January 1, 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.

Revision of Prior Balance Sheet. During the first quarter of 2017, the Company identified an error related to the deferred income tax treatment associated with its Wholesale and Retail Contra AFUDC Regulatory Liability. The Company evaluated the materiality of the error and concluded that it was not material to any previously issued historical financial statements. The Company has revised its Consolidated Balance Sheet as of December 31, 2016, by decreasing Regulatory Assets and Deferred Income Taxes by $29.5 million. The correction had no impact on our Consolidated Statement of Income.

Reclassification of Prior Income Statement. Beginning with the second quarter of 2017, the Company enhanced its presentation of Operating Revenue and certain Operating Expenses on the Consolidated Statement of Income by presenting the caption Operating Revenue separately as Operating Revenue – Utility and Operating Revenue – Non-utility. In conformity with the current presentation, we now present $1,007.7 million and $991.2 million of Operating Revenue as Operating Revenue – Utility for the years ended December 31, 2016, and 2015, respectively, as it is generated from our regulated utility operations. Non-utility revenue of $339.0 million and $495.2 million for the years ended December 31, 2016, and 2015 respectively, is now presented as Operating Revenue – Non-utility. In addition, the captions Fuel and Purchased Power and Cost of Sales have been updated to Fuel, Purchased Power and Gas – Utility and Cost of Sales – Non-utility. As a result, we have reclassified $7.0 million relating to the cost of gas sales at SWL&P from the historic caption Cost of Sales to Fuel, Purchased Power and Gas – Utility for the year ended December 31, 2016, and $7.9 million for the year ended December 31, 2015.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2017			2016
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,523.7			$4,437.0
Construction Work in Progress	121.6			84.2
Accumulated Depreciation	(1,520.5		)	(1,426.1		)
Regulated Operations – Net	3,124.8			3,095.1
ALLETE Clean Energy
Property, Plant and Equipment in Service	482.5			472.3
Construction Work in Progress	144.9			101.0
Accumulated Depreciation	(60.8		)	(41.0		)
ALLETE Clean Energy – Net	566.6			532.3
U.S. Water Services
Property, Plant and Equipment in Service	24.8			19.5
Accumulated Depreciation	(10.4		)	(6.9		)
U.S. Water Services – Net	14.4			12.6
Corporate and Other (a)
Property, Plant and Equipment in Service	204.7			179.8
Construction Work in Progress	5.0			2.8
Accumulated Depreciation	(93.1		)	(81.4		)
Corporate and Other – Net	116.6			101.2
Property, Plant and Equipment – Net		$3,822.4			$3,741.2


(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
Regulated Operations		ALLETE Clean Energy (a)	5 to 35 years
Generation	5 to 50 years	U.S. Water Services	3 to 39 years
Transmission	44 to 67 years	Corporate and Other	3 to 50 years
Distribution	18 to 65 years


(a)	ALLETE Clean Energy’s Property, Plant and Equipment consists primarily of WTGs with estimated useful lives ranging from 30 years to 35 years.

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, removal liabilities have not been recognized because they are considered immaterial to our Consolidated Financial Statements.

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, 2015		$131.4
Accretion	8.0
Liabilities Settled	(6.5		)
Revisions in Estimated Cash Flows	3.7
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

Jointly-Owned Facilities and Projects

12 Months Ended

Dec. 31, 2017

Jointly-Owned Facilities and Projects [Abstract]

Jointly-Owned Facilities and Projects [Text Block]

JOINTLY-OWNED FACILITIES AND PROJECTS

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 three CapX2020 projects which were completed and placed in service in 2011, 2012 and 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, 2017
Boswell Unit 4		$668.2		$222.8		$8.2	80
CapX2020 Projects	101.0		8.4		—		9.3 - 14.7
Total		$769.2		$231.2		$8.2
As of December 31, 2016
Boswell Unit 4		$668.1		$211.2		$8.1	80
CapX2020 Projects	101.2		5.9		—		9.3 - 14.7
Total		$769.3		$217.1		$8.1

Regulatory Matters

12 Months Ended

Dec. 31, 2017

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 $96.9 million in 2017 ($97.1 million in 2016; $89.6 million in 2015).

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 seeking 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. On an annualized basis, the requested final rate increase would have generated approximately $55 million in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017.

On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately $49 million on an annualized basis. At a hearing on January 18, 2018, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Upon commencement of final rates, we expect additional revenue of approximately $13 million on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which will be fully offset by the recognition of a corresponding reserve. As a result of the MPUC’s decisions on January 18, 2018, Minnesota Power has recorded a reserve for an interim rate refund of approximately $32 million as of December 31, 2017. The MPUC also disallowed recovery of 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. An order from the MPUC setting forth the effective date of final rates is expected by March 12, 2018. Minnesota Power will review this order for potential reconsideration of certain issues at that time.

As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million pre-tax in 2017.

Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 which established that it is the energy policy of Minnesota to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued on October 13, 2017, that modified the order dated April 20, 2017. During 2017, Minnesota Power provided discounts of $8.6 million which were recorded as a receivable. On September 29, 2017, Minnesota Power informed its EITE customers that it has suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately $15 million annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, EITE discounts will offset interim rate refund reserves for non-EITE customers.

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.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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, 2021, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided a contract termination notice in June 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 at least December 31, 2024. 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 in place for certain transmission investments and expenditures. In a February 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.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to Bison, and the restoration and repair of Thomson. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of constructing 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 8, 2017.

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 approximately $15 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 an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order.

In an order dated December 7, 2017, 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 approximately $14 million in 2017. The North Dakota investment tax credits 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.

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

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a December 2016 order; however, in an order dated March 22, 2017, the MPUC approved a request by Minnesota Power to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.)

Fuel Adjustment Clause Reform Pilot. In an order dated December 19, 2017, the MPUC adopted a three-year pilot program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order changes 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. The three-year pilot program is expected to begin in 2019. 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 in this proceeding resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017.

Tax Cuts and Jobs Act of 2017. On December 29, 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 January 19, 2018, the MPUC issued a notice of request for information and established comment periods with an initial filing required by March 2, 2018. On January 10, 2018, the PSCW also opened a docket to review the effects of this legislation and directed Wisconsin utilities to defer its impacts until further direction is provided by the PSCW. We have recorded the impact of the remeasurement of deferred income tax assets and liabilities resulting from the federal income tax rate change of the TCJA for Minnesota Power and SWL&P as regulatory assets and liabilities as the benefits of the TCJA are expected to be passed back to our customers over time. (See Regulatory Assets and Liabilities.) The final amount and timing over which the benefits of the TCJA will be passed back to customers is expected to be determined in these dockets; however, we are unable to predict the outcome of these regulatory proceedings.

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2017 PSCW retail rate order effective August 14, 2017, that allows for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 14, 2017, were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity. The 2017 PSCW retail rate order authorizes SWL&P to collect on average a 2.9 percent increase in rates for retail customers (3.8 percent increase in electric rates; 4.8 percent decrease in natural gas rates; and 9.8 percent increase in water rates). On an annualized basis, SWL&P expects to collect additional revenue of $2.5 million.

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 September 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 the next decade. In a July 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. In October 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018.

On July 28, 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 energy PPA. These agreements will be subject to MPUC approval of the construction of 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 September 19, 2017, the MPUC approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2019, and Minnesota Power’s request that approval for the natural gas energy PPA be decided through an administrative law judge process. The administrative law judge is expected to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second half of 2018. The MPUC did not take any action regarding the wind and solar energy PPAs which will be refiled separately from the natural gas energy PPA.

NOTE 4. REGULATORY MATTERS (Continued)

Great Northern Transmission Line. Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range. In 2015, a certificate of need was approved by the MPUC. Based on this approval, 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.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 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. 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 contributions in aid of construction. Total project costs of $152.4 million have been incurred through December 31, 2017, of which $67.6 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. In December 2016, Manitoba Hydro filed an application with the National Energy Board in Canada requesting authorization to construct and operate an international transmission line. Both provincial and federal approvals are pending. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014 and is anticipated to be in service by early 2021.

Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year and establish an annual energy-savings goal of 1.5 percent of annual retail energy sales. These investments are recovered from certain retail customers through a combination of the conservation cost recovery charge included in retail base rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge on the deferred account balance. Minnesota Power refers to its conservation programs collectively as the “Power of One”. On November 16, 2017, the Minnesota Department of Commerce approved Minnesota Power’s modified CIP triennial filing for 2017 through 2019, which outlines Minnesota Power’s CIP spending and energy-saving goals for 2017 through 2019. Minnesota Power’s CIP investment goal was $10.3 million for 2017 ($7.3 million for 2016; $7.1 million for 2015), with actual spending of $8.1 million in 2017 ($7.4 million in 2016; $6.6 million in 2015). The investment goals for 2018 and 2019 are $10.3 million and $10.5 million, respectively.

On April 3, 2017, Minnesota Power submitted its 2016 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $5.5 million based upon MPUC procedures. In an order dated June 22, 2017, 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 2017. The approved financial incentive will be recovered through customer billing rates in 2017 and 2018. In 2016 and 2015, the CIP financial incentives recognized were $7.5 million and $6.2 million, respectively. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

MISO Return on Equity Complaints. In 2013, several customer groups located within the MISO service area filed complaints with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ALLETE and ATC, to 9.15 percent. In 2015, a federal administrative law judge ruled on the complaint proposing a reduction in the base return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In September 2016, the FERC issued an order affirming the administrative law judge’s recommendation.

In 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. In June 2016, a federal administrative law judge ruled on the additional complaint proposing a further 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.

NOTE 4. REGULATORY MATTERS (Continued)

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 40kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved Camp Ripley, a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. Minnesota Power believes Camp Ripley and the community solar garden arrays will meet approximately one‑third of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. The proposal to incentivize customer‑sited solar installations and the community solar garden subscriptions is expected to meet a portion of the required small scale 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. No regulatory assets or liabilities 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	2017		2016
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause	—			$18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	$220.3		226.1
Income Taxes (c)(d)	112.8		33.8
Asset Retirement Obligations (e)	29.6		26.0
Manufactured Gas Plant (f)	8.1		1.0
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program (g)	3.3		4.0
Cost Recovery Riders (h)	—		30.5
Other	5.6		3.7
Total Non-Current Regulatory Assets	384.7		330.1
Total Regulatory Assets		$384.7		$348.7
Non-Current Regulatory Liabilities
Income Taxes (d)		$411.2		$19.1
Wholesale and Retail Contra AFUDC (i)	57.9		56.8
Provision for Interim Rate Refund (j)	23.7		—
Plant Removal Obligations	20.3		19.1
North Dakota Investment Tax Credits (k)	14.1		28.2
Cost Recovery Riders (h)	2.2		—
Other	2.6		2.6
Total Non-Current Regulatory Liabilities		$532.0		$125.8


(a)	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. (See 2016 Minnesota General Rate Case.)

(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)	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

(d)

These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The increase in 2017 is primarily due to the remeasurement of deferred income tax assets and liabilities for our Regulated Operations resulting from the TCJA. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the U.S. Internal Revenue Code over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. (See Note 1. Operations and Significant Accounting Policies, and Tax Cuts and Jobs Act of 2017.) The balances not related to remeasurement will decrease over the remaining life of the related temporary differences and flow through current income taxes.


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


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


(g)	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.

(h)

The cost recovery rider regulatory assets and liabilities are revenues not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL, and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets and liabilities as of December 31, 2017, will be recovered or returned within the next two years.


(i)	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.


(j)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $8.6 million of EITE discounts that will be offset against interim rate refunds. (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(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 fillings as the tax credits are utilized.

Investment in ATC

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Investment in ATC [Text Block]

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, 2017, our equity investment in ATC was $118.7 million ($135.6 million as of December 31, 2016). On January 31, 2018, we invested an additional $1.6 million in ATC. In total, we expect to invest approximately $6 million throughout 2018.



ALLETE’s Investment in ATC
Year Ended December 31	2017			2016
Millions
Equity Investment Beginning Balance		$135.6			$124.5
Cash Investments	7.8			5.4
Equity in ATC Earnings	22.5			18.5
Distributed ATC Earnings	(19.3		)	(12.8		)
Remeasurement of Deferred Income Taxes (a)	(27.9		)	—
Equity Investment Ending Balance		$118.7			$135.6


(a)	Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2017		2016
Millions
Current Assets		$87.7		$75.8
Non-Current Assets	4,598.9		4,312.9
Total Assets		$4,686.6		$4,388.7
Current Liabilities		$767.2		$495.1
Long-Term Debt	1,790.6		1,865.3
Other Non-Current Liabilities	240.3		271.5
Members’ Equity	1,888.5		1,756.8
Total Liabilities and Members’ Equity		$4,686.6		$4,388.7



Income Statement Data
Year Ended December 31	2017		2016		2015
Millions
Revenue		$721.6		$650.8		$615.8
Operating Expense	344.9		322.5		319.3
Other Expense	104.1		95.5		96.1
Net Income		$272.6		$232.8		$200.4
ALLETE’s Equity in Net Income		$22.5		$18.5		$16.3

In September 2016, the FERC issued an order reducing ATC’s authorized return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. Prior to this order, ATC had been allowed a return on equity of 12.2 percent which had been impacted by reductions for estimated refunds related to complaints filed with the FERC by several customers located within the MISO service area.

In June 2016, a federal administrative law judge ruled on an additional complaint proposing a further 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. (See Note 4. Regulatory Matters.)

Acquisitions

12 Months Ended

Dec. 31, 2017

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, 2017, 2016 and 2015.

2017 Activity.

Tonka Water. On September 1, 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 and will expand 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 allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to income tax liabilities; subsequent adjustments could impact the amount of goodwill recorded. 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 April 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.

WEST. In October 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 the first six months of 2017 and a $0.6 million payment is due 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.

NOTE 6. ACQUISITIONS (Continued)

2016 Activity (Continued)

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 the second quarter of 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.

2015 Activity.

U.S. Water Services. In 2015, ALLETE acquired U.S. Water Services. Total consideration for the transaction was $202.3 million, which included payment of $166.6 million in cash and an estimated fair value of earnings-based contingent consideration of $35.7 million, as estimated at the date of acquisition, to be paid through 2019. The contingent consideration is presented within Other Non-Current Liabilities on the Consolidated Balance Sheet. The Consolidated Statement of Income reflects 100 percent of the results of operations for U.S. Water Services since the acquisition date as the Company has acquired 100 percent of U.S. Water Services.

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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.

NOTE 6. ACQUISITIONS (Continued)

2015 Activity (Continued)



Millions
Assets Acquired
Cash and Cash Equivalents		$0.9
Accounts Receivable	16.8
Inventories (a)	13.4
Other Current Assets (b)	5.3
Property, Plant and Equipment	10.6
Intangible Assets (c)	83.0
Goodwill (d)	122.9
Other Non-Current Assets	0.2
Total Assets Acquired		$253.1
Liabilities Assumed
Current Liabilities		$19.2
Non-Current Liabilities	31.6
Total Liabilities Assumed		$50.8
Net Identifiable Assets Acquired		$202.3


(a)	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of Sales within one year from the acquisition date.


(b)	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog was recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for standby letters of credit.


(c)	Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 7. Goodwill and Intangible Assets.)


(d)	For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill.

Acquisition-related costs of $3.0 million after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Chanarambie/Viking. In 2015, ALLETE Clean Energy acquired 100 percent of wind energy facilities in southern Minnesota (Chanarambie/Viking) from EDF Renewable Energy, Inc. for $48.0 million.

The facilities have a combined 97.5 MW of generating capability. The wind energy facilities began commercial operations in 2003 and have PSAs in place for their entire output, which expire in 2018 (12 MW) and 2023 (85.5 MW).

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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.

NOTE 6. ACQUISITIONS (Continued)

2015 Activity (Continued)



Millions
Assets Acquired
Current Assets		$4.8
Property, Plant and Equipment	103.0
Other Non-Current Assets (a)	1.0
Total Assets Acquired		$108.8
Liabilities Assumed
Current Liabilities (b)		$6.7
PSAs	49.0
Non-Current Liabilities	5.1
Total Liabilities Assumed		$60.8
Net Identifiable Assets Acquired		$48.0


(a)	Included in Other Non-Current Assets was $0.3 million of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Current Liabilities included $5.9 million related to the current portion of PSAs.

Acquisition-related costs of $0.2 million after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Armenia Mountain. In 2015, ALLETE Clean Energy acquired 100 percent of a wind energy facility located near Troy, Pennsylvania (Armenia Mountain) from The AES Corporation and a minority shareholder for $111.1 million, plus the assumption of existing debt.

The facility has 100.5 MW of generating capability, began commercial operations in 2009, and has PSAs in place for its entire output, which expire in 2024.

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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Current Assets (a)		$9.0
Property, Plant and Equipment	156.2
Other Non-Current Assets (b)	14.4
Total Assets Acquired		$179.6
Liabilities Assumed
Current Liabilities		$2.9
Long-Term Debt Due Within One Year	5.9
Long-Term Debt	55.0
Other Non-Current Liabilities	4.7
Total Liabilities Assumed		$68.5
Net Identifiable Assets Acquired		$111.1


(a)	Included in Current Assets was $1.0 million related to the current portion of PSAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.


(b)	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PSAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

NOTE 6. ACQUISITIONS (Continued)

2015 Activity (Continued)

Acquisition-related costs of $1.6 million after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

A and W Technologies. In 2015, U.S. Water Services acquired 100 percent of A and W Technologies, Inc. (AWT). Total consideration for the transaction was $9.3 million, which included payment of $8.3 million in cash and a $1.0 million payment made in April 2017. AWT, similar to U.S. Water Services, is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southeastern 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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Current Assets		$1.0
Property, Plant and Equipment	0.1
Intangible Assets (a)	3.9
Goodwill (b)	4.4
Total Assets Acquired		$9.4
Liabilities Assumed
Current Liabilities		$0.1
Total Liabilities Assumed		$0.1
Net Identifiable Assets Acquired		$9.3


(a)	Intangible Assets include customer relationships and non-compete agreements. (See Note 7. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill.

Acquisition-related costs were immaterial, expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2017

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:



	ALLETE Clean Energy			U.S. Water Services		Total
Millions
Balance as of December 31, 2015		$3.3			$127.3		$130.6
Acquired Goodwill (a)	—			3.9		3.9
Impairment Charge (b)	(3.3		)	—		(3.3		)
Balance as of December 31, 2016	—			131.2		131.2
Acquired Goodwill (a)	—			16.9		16.9
Other Adjustments (c)	—			0.2		0.2
Balance as of December 31, 2017	—				$148.3		$148.3


(a)	See Note 6. Acquisitions.

(b)


(c)	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition.

The following table summarizes changes to intangible assets, net, for the year ended December 31, 2017:



	December 31, 2016		Additions (a)		Amortization	December 31, 2017
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$59.3	—		$(4.6)		$54.7
Developed Technology and Other (b)	6.3			$0.9	(0.9)	6.3
Total Definite-Lived Intangible Assets	65.6		0.9		(5.5)	61.0
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$82.2		$0.9	$(5.5)		$77.6


(a)	Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 6. Acquisitions.)


(b)	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 20 years, and developed technology and other have remaining useful lives ranging from approximately 1 year to approximately 11 years (weighted average of approximately 7 years). The weighted average remaining useful life of all definite-lived intangible assets as of December 31, 2017, is approximately 19 years.

Amortization expense of intangible assets for the year ended December 31, 2017, was $5.5 million ($5.2 million in 2016; $4.0 million in 2015). Accumulated amortization was $14.8 million and $9.3 million as of December 31, 2017, and December 31, 2016, respectively. Estimated amortization expense for definite-lived intangible assets is $5.3 million in 2018, $5.0 million in 2019, $4.7 million in 2020, $4.6 million in 2021, $4.3 million in 2022 and $37.1 million thereafter.

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Investments

12 Months Ended

Dec. 31, 2017

Investments [Text Block]

INVESTMENTS

Investments. As of December 31, 2017, the investment portfolio included the legacy real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans and other assets consisting primarily of land in Minnesota.



Other Investments
As of December 31	2017		2016
Millions
ALLETE Properties		$26.4		$31.7
Available-for-sale Securities (a)	19.1		18.8
Cash Equivalents	3.8		1.3
Other	3.8		3.8
Total Other Investments		$53.1		$55.6


(a)	As of December 31, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $3.2 million, in three years to less than five years was $3.6 million, and in five or more years was $1.4 million.

Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairment was recorded in 2017 (none in 2016; $36.3 million in 2015). (See Note 1. Operations and Significant Accounting Policies.)

Available-for-Sale Securities. We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.

Gross realized and unrealized gains and losses on our available-for-sale securities were immaterial in 2017, 2016 and 2015.

Fair Value

12 Months Ended

Dec. 31, 2017

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 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.

NOTE 9. FAIR VALUE (Continued)

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017, and December 31, 2016. 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, 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, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.1	—		—			$7.1
Available-for-sale – Corporate and Governmental Debt Securities	—			$11.7	—		11.7
Cash Equivalents	1.3		—		—		1.3
Total Fair Value of Assets		$8.4		$11.7	—			$20.1

Liabilities: (b)
Deferred Compensation	—			$16.0	—			$16.0
U.S. Water Services Contingent Consideration	—		—			$25.0	25.0
Total Fair Value of Liabilities	—			$16.0		$25.0		$41.0
Total Net Fair Value of Assets (Liabilities)		$8.4	$(4.3)		$(25.0)		$(20.9)


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


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

NOTE 9. FAIR VALUE (Continued)

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, 2017, and December 31, 2016. 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 $5.4 million as of December 31, 2017.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2015		$36.6
Accretion (a)	2.8
Payments	(0.8		)
Changes in Cash Flow Projections (b)	(13.6		)
Balance as of December 31, 2016		$25.0
Accretion (a)	0.8
Payments (c)	(19.7		)
Changes in Cash Flow Projections (c)	(0.7		)
Balance as of December 31, 2017		$5.4


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

(b)

During the fourth quarter of 2016, management assessed earnings estimates used in calculating the fair value of the U.S. Water Services contingent consideration liability and determined an adjustment was necessary to the liability’s carrying amount based on its assessment. As a result, we recorded a reduction of $13.6 million to the liability’s carrying amount which resulted in an after-tax gain of the same amount presented within Operating Expenses – Other in the Consolidated Statement of Income.


(c)	Payments and changes in cash flow projections 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 the first half of 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, 2017 and 2016, there were no transfers in or out of Levels 1, 2 or 3.

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



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
December 31, 2017	$1,513.3	$1,627.6
December 31, 2016	$1,569.1	$1,653.8

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.

NOTE 9. FAIR VALUE (Continued)

Equity Method Investment. Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC. (See Note 5. Investment in ATC.) The aggregate carrying amount of the investment was $118.7 million as of December 31, 2017 ($135.6 million as of December 31, 2016). The Company assesses our investment in ATC for impairment whenever events or changes in circumstances indicate that the carrying amount of our investment in ATC may not be recoverable. For the years ended December 31, 2017 and 2016, there were no indicators of impairment.

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 $148.3 million as of December 31, 2017, and $131.2 million as of December 31, 2016.

Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. 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, 2017 (none in 2016 and in 2015). 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 $77.6 million as of December 31, 2017 ($82.2 million as of December 31, 2016). 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, 2017, 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. In 2015, the Company implemented a revised strategy for its real estate assets and recorded a non-cash impairment charge of $36.3 million for ALLETE Properties, reducing the carrying value of the real estate to its estimated fair value. (See Note 1. Operations and Significant Accounting Policies.) For the year ended December 31, 2017, there were no indicators of impairment.

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

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, 2017

Debt Disclosure [Abstract]

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2017, total short-term debt outstanding was $64.1 million ($187.7 million as of December 31, 2016), consisted of long-term debt due within one year and included $0.5 million of unamortized debt issuance costs.

As of December 31, 2017, we had consolidated bank lines of credit aggregating $407.0 million ($409.0 million as of December 31, 2016), the majority of which expire in October 2020. We had $11.9 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of December 31, 2017 ($11.1 million in standby letters of credit and no outstanding draws as of December 31, 2016).

Long-Term Debt. As of December 31, 2017, total long-term debt outstanding was $1,439.2 million ($1,370.4 million as of December 31, 2016) and included $9.5 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2018 is $64.6 million; $57.6 million in 2019; $143.0 million in 2020; $97.8 million in 2021; $88.0 million in 2022; and $1,062.3 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 June 1, 2017, ALLETE issued $80.0 million of its senior unsecured notes (the Notes) to certain institutional buyers in the private placement market. The Notes were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes bear interest at 3.11 percent and mature on June 1, 2027. Interest on the Notes is payable semi-annually in June and December of each year, commencing on December 1, 2017. ALLETE has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes were used to redeem debt, fund corporate growth opportunities and for general corporate purposes.

On August 25, 2017, ALLETE entered into a $40.0 million term loan agreement (Term Loan). The Term Loan is an unsecured, single draw loan that is due on August 25, 2020, and may be prepaid at any time subject to a make-whole provision. Interest on the Term Loan is payable quarterly at a rate per annum equal to LIBOR plus 1.025 percent. Proceeds from the Term Loan were used for general corporate purposes.

On November 2, 2017, ALLETE entered into a bond purchase agreement providing for the issuance and sale of $60.0 million of its First Mortgage Bonds (the Bonds) that bear interest at 4.07 percent. The Bonds will be issued on or about April 1, 2018, and will mature in April 2048. Interest on the Bonds will be payable 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. The company intends to use the proceeds from the sale of the Bonds to fund utility capital expenditures 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)



Long-Term Debt
As of December 31	2017			2016
Millions
First Mortgage Bonds
1.83% Series Due 2018		$50.0			$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
Unsecured Term Loan Variable Rate Due 2017	—			125.0
Senior Unsecured Notes 5.99% Due 2017	—			50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Unsecured Term Loan Variable Rate Due 2020	40.0			—
Armenia Mountain Senior Secured Notes 3.26% Due 2024	65.9			74.6
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			—
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0			15.0
Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037	69.1			61.2
Unamortized Debt Issuance Costs	(10.0		)	(11.0		)
Total Long-Term Debt	1,503.3			1,558.1
Less: Due Within One Year	64.1			187.7
Net Long-Term Debt		$1,439.2			$1,370.4

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, 2017, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of December 31, 2017, ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2017

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, 2017
Millions	2018		2019		2020		2021		2022		Thereafter
Coal, Rail and Shipping Contracts		$29.0		$1.8	—		—		—		—
Leasing Agreements		$14.2		$12.8		$9.5		$7.3		$6.1		$30.0
Long-term Service Agreements (a)		$11.0		$0.9	—		—			$1.0		$11.0
PPAs (b)		$104.5		$107.1		$115.0		$144.8		$144.7		$1,667.0


(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 Tenaska commencing in 2020 as it is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired facility. (See Power Purchase Agreements.)

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 2018 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 2018. 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 $17.5 million in 2017 ($17.1 million in 2016; $17.3 million in 2015).

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

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, 2017, Square Butte had total debt outstanding of $330.0 million. Annual debt service for Square Butte is expected to be approximately $49 million in each of the next five years, 2018 through 2022, 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 2017 was $75.7 million ($73.3 million in 2016; $77.8 million in 2015). 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 $9.4 million in 2017 ($9.6 million in 2016; $10.1 million in 2015). 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 Agreements (Continued)

Minnesota Power has also entered into the following agreements for the purchase or sale of capacity and energy as of December 31, 2017:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Great River Energy
PPA 1	50 MW	Capacity / Energy	June 2016	May 2020	(a)
PPA 2	50 MW	Capacity	June 2016	May 2020	Fixed
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
Manitoba Hydro
PPA 1	(b)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	50 MW	Capacity / Energy	June 2015	May 2020	(c)
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
PPA 4 (d)	250 MW	Capacity / Energy	June 2020	May 2035	(e)
PPA 5 (d)	133 MW	Energy	(f)	(f)	Forward Market Prices
Minnkota Power	50 MW	Capacity / Energy	June 2016	May 2020	(g)
Oliver Wind I	(h)	Energy	December 2006	December 2031	Fixed
Oliver Wind II	(h)	Energy	December 2007	December 2032	Fixed
Shell Energy	50 MW	Energy	January 2017	December 2019	Fixed
TransAlta	(i)	Energy	January 2017	December 2019	Fixed
Tenaska (j)	(j)	Capacity / Energy	June 2020	June 2040	Fixed
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(k)
PSA 2	100 MW	Capacity	June 2016	May 2018	Fixed
PSA 3	50 MW	Capacity	June 2017	May 2019	Fixed
Minnkota Power	(l)	Capacity / Energy	June 2014	December 2026	(l)
Silver Bay Power	(m)	Energy	January 2017	December 2031	(n)


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


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


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


(d)	Agreements are subject to the construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. (See Great Northern Transmission Line.)


(e)	The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.


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


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


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


(i)	The energy purchased under the 50 MW PPA is during off-peak hours and the 100 MW PPA is during on-peak hours.


(j)	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota and is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired facility. (See Note 4. Regulatory Matters.)


(k)	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.

(l)

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 2017 (28 percent in 2016 and in 2015). (See Square Butte PPA.)

(m)

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. In the years 2016 through 2019, Minnesota Power is supplying Silver Bay Power with at least 50 MW of energy and Silver Bay Power has the option to purchase additional energy. On December 31, 2019, Silver Bay Power will cease self-generation and Minnesota Power will supply the energy requirements for Silver Bay Power.


(n)	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.

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 the 250 MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

In 2015, a certificate of need was approved by the MPUC. Based on this approval, 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 Note 4. Regulatory Matters.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 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. 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 contributions in aid of construction. Total project costs of $152.4 million have been incurred through December 31, 2017, of which $67.6 million has been recovered from a subsidiary of Manitoba Hydro.

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 recently been promulgated by both the EPA and state authorities. 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 finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may 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 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in 2011 alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota in 2014. 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. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as part of its EnergyForward strategic plan. 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.

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; rather it requires 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.

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.

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.

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. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.


•	Ozone NAAQS. All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data; however, some areas in the metropolitan Twin Cities and southwest portion of the state are close to exceeding the standard. As a result, voluntary efforts to reduce ground-level ozone continue in the state. No additional costs for compliance are anticipated at this time.

•

Particulate Matter NAAQS. The EPA has designated the entire state of Minnesota as unclassifiable/attainment; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. In September 2016, environmental groups filed a lawsuit against the EPA in the U.S. District Court for the Northern District of California alleging the EPA had failed to fully implement the PM_2.5standards in certain states, including Minnesota, by not enforcing states’ submittals of required infrastructure implementation plans for the 2012 PM_2.5NAAQS. The outcome of this litigation is uncertain, and as such, any costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.


•	NO₂ NAAQS. Ambient monitoring data indicates that Minnesota is likely in compliance with the one-hour NAAQS standard for NO₂. On July 16, 2017, the EPA proposed retaining the current one-hour and annual NO₂NAAQS. Additional compliance costs for the one-hour NO₂NAAQS are not expected at this time.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

•

SO₂NAAQS. In 2015, the EPA finalized the SO₂ data requirements rule (DRR) for the 2010 one-hour NAAQS to assist the states in implementing the standard. The MPCA initially informed Minnesota Power that compliant SO₂ modeling completed at Minnesota Power's Boswell and Taconite Harbor facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also require facilities have federally-enforceable permit limits at which the one-hour SO₂NAAQS compliance was modeled by January 13, 2017. Taconite Harbor was issued an amended air permit in September 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 13, 2017, deadline to amend the Boswell permit. The MPCA is in discussions with the EPA on alternate compliance pathways to use existing completed modeling at current limits. On August 21, 2017, the EPA proposed retaining the current primary SO₂one-hour NAAQS. Compliance costs for the one-hour SO₂NAAQS are not 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 our renewable power supply;


•	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; and


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

EPA Regulation of GHG Emissions. In 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements, however, GHG requirements may be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

In 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established higher permitting thresholds for GHG than for other pollutants subject to PSD; however, the court also upheld the EPA’s ability to require best available control technology (BACT) for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions.

In October 2016, the EPA published a proposed rule in the Federal Register to revise its PSD and Title V regulatory provisions concerning GHG emissions. In this proposed rule, the EPA proposes to amend its regulations to clarify that a source’s obligation to obtain a PSD or Title V permit is triggered only by non-GHG pollutants. If the PSD or Title V permitting requirements are triggered by non-GHG, NSR pollutants, then these programs will also apply to the source’s GHG emissions. The proposed rule, as currently written, is not expected to have a material impact on the Title V permitting for current operations.

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 February 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In September 2016, the U.S. Court of Appeals for the District of Columbia 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; however, the MPCA has been holding a series of meetings on the CPP for educational and planning purposes in the interim. Minnesota Power has been actively involved in these MPCA meetings, and is closely monitoring the appeals process.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 has 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. On October 10, 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. On December 28, 2017, an Advanced Notice of Proposed Rulemaking (ANPRM) for a CPP replacement rule was published in the Federal Register.

Minnesota Power is currently evaluating the CPP rescission and recently proposed ANPRM for a CPP replacement rule as it relates to the State of Minnesota as well as its potential impact on the Company. Minnesota has already initiated several measures consistent with those called for under the CPP. 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 4. 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 National Pollutant Discharge Elimination System (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.

Clean Water Act - Aquatic Organisms. In 2014, EPA regulations under Section 316(b) of the Clean Water Act setting standards applicable to cooling water intake structures for the protection of aquatic organisms became effective. The regulations require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule will be implemented through NPDES permits issued to covered facilities. No NPDES permits for Minnesota Power facilities have been re-issued containing Section 316(b) requirements since the final rule became effective. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment indicates that Minnesota Power could incur costs of compliance up to $15 million over the next five years. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Steam Electric Power Generating Effluent Guidelines. In 2015, the EPA issued revised federal effluent limit 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. On September 13, 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 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, but may do so in the future. Under the existing ELG rule, bottom ash transport water discharge 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 for several years to reduce the amount of water discharged and evaluate potential re-use options in its plant processes.

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 reuse. 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 the necessary reports to the EPA.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 which has been idled and has a temporary landfill cover in place, 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 10 years and be between approximately $65 million and $100 million. The EPA has indicated to Minnesota Power that the Taconite Harbor landfill 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. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. On September 13, 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA. Compliance costs, if any, for CCR at Taconite Harbor cannot be estimated 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, 2017, we have recorded a liability of approximately $8 million for remediation costs at this site, and a corresponding 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 2018 and 2032. As of December 31, 2017, ALLETE Clean Energy has $15.4 million outstanding in standby letters of credit.

U.S. Water Services. As of December 31, 2017, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of December 31, 2017, 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.

ALLETE Properties. As of December 31, 2017, 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Community Development District Obligations. In 2005, the Town Center District issued $26.4 million of tax-exempt, 6.0 percent capital improvement revenue bonds, 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 our portion of these assessments, based upon its ownership of benefited property. As of December 31, 2017, we owned 70 percent of the assessable land in the Town Center District (72 percent as of December 31, 2016) and 33 percent of the assessable land in the Palm Coast Park District (92 percent as of December 31, 2016). As of December 31, 2017, 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 $2.0 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.

Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2017

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, 2014	45,929			$1,107.6
Employee Stock Purchase Plan	18		0.9
Invest Direct	383		19.0
Options and Stock Awards	43		8.6
Equity Issuance Program	1,289		69.9
Forward Sale Agreement and Issuance	1,413		65.4
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
Contributions to Pension	216		13.5
Balance as of December 31, 2017	51,117			$1,401.4

NOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)

Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc., in 2008, as amended most recently in August 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, 2017. For the year ended December 31, 2017, 1.0 million shares of common stock were issued under this agreement, resulting in net proceeds of $65.7 million (0.1 million shares for net proceeds of $8.0 million in 2016; 1.3 million shares for net proceeds of $69.9 million in 2015). 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. The shares issued in 2015 were offered and sold pursuant to Registration Statement No. 333-190335.

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, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). No options to purchase shares of common stock were excluded from the computation of diluted earnings per share in 2017, 2016 and 2015.

Forward Sale Agreement and Issuance of Common Stock. In 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock.

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock from third parties and sold them to the underwriters. The forward sale price was $48.01 per share, subject to adjustment as provided in the Agreement. In 2014, ALLETE physically settled a portion of its obligations under the Agreement by delivering approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million, and in February 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares of common stock for cash proceeds of $65.4 million.

Contributions to Pension. For the year ended December 31, 2017, we contributed approximately 0.2 million shares of ALLETE common stock to our pension plan, which had an aggregate value of $13.5 million when contributed (none in 2016 and in 2015). These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
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
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
2015
Net Income Attributable to ALLETE		$141.1			$141.1
Average Common Shares	48.3		0.1	48.4
Earnings Per Share		$2.92			$2.92

Income Tax Expense

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2017			2016			2015
Millions
Current Income Tax Expense (a)
Federal	—			—			—
State	$0.3			$0.4			$0.2
Total Current Income Tax Expense		$0.3			$0.4			$0.2
Deferred Income Tax Expense
Federal		$12.1			$12.0			$19.4
Federal – Remeasurement of Deferred Income Taxes (b)	(13.0		)	—			—
State	15.8			8.1			6.5
Investment Tax Credit Amortization	(0.5		)	(0.7		)	(0.8		)
Total Deferred Income Tax Expense		$14.4			$19.4			$25.1
Total Income Tax Expense		$14.7			$19.8			$25.3


(a)	For the years ended December 31, 2017, 2016 and 2015, 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. The federal and state NOLs will be carried forward to offset future taxable income.


(b)	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2017			2016			2015
Millions
Income Before Non-Controlling Interest and Income Taxes		$186.9			$175.6			$166.8
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$65.4			$61.5			$58.4
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	10.5			5.6			4.4
Regulatory Differences for Utility Plant	—			(0.1		)	(0.6		)
Production Tax Credits	(45.1		)	(41.5		)	(37.0		)
Change in Fair Value of Contingent Consideration	—			(3.8		)	—
Remeasurement of Deferred Income Taxes (a)	(13.0		)	—			—
Other	(3.1		)	(1.9		)	0.1
Total Income Tax Expense		$14.7			$19.8			$25.3


(a)	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)

The effective tax rate was 7.9 percent for 2017 (11.3 percent for 2016; 15.2 percent for 2015). 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. (See Note 1. Operations and Significant Accounting Policies.) The 2016 and 2015 effective rates were primarily impacted by production tax credits.

NOTE 13. INCOME TAX EXPENSE (Continued)



Deferred Income Tax Assets and Liabilities
As of December 31	2017			2016
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation		$65.9			$104.6
Property Related	104.3			110.5
NOL Carryforwards	99.1			185.6
Tax Credit Carryforwards	294.3			227.4
Power Sales Agreements	35.0			59.3
Regulatory Liabilities	117.7			7.3
Other	33.3			46.9
Gross Deferred Income Tax Assets	749.6			741.6
Deferred Income Tax Asset Valuation Allowance	(60.0		)	(43.0		)
Total Deferred Income Tax Assets		$689.6			$698.6
Deferred Income Tax Liabilities
Property Related		$758.3			$1,039.6
Regulatory Asset for Benefit Obligations	61.4			91.9
Unamortized Investment Tax Credits	32.8			33.3
Partnership Basis Differences	34.9			50.9
Regulatory Assets	32.0			25.6
Other	0.7			11.9
Total Deferred Income Tax Liabilities		$920.1			$1,253.2
Net Deferred Income Taxes (a)		$230.5			$554.6


(a)	Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet. Additionally, see Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.



NOL and Tax Credit Carryforwards
As of December 31	2017	2016
Millions
Federal NOL Carryforwards (a)	$375.2		$485.3
Federal Tax Credit Carryforwards	$209.2	$163.7
State NOL Carryforwards (a)	$289.9	$294.4
State Tax Credit Carryforwards (b)	$25.6	$21.0


(a)	Pre-tax amounts.


(b)	Net of a $59.5 million valuation allowance as of December 31, 2017 ($42.7 million as of December 31, 2016).

The federal NOL and tax credit carryforward periods expire between 2030 and 2037. 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, 2017. 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.

NOTE 13. INCOME TAX EXPENSE (Continued)



Gross Unrecognized Income Tax Benefits	2017			2016			2015
Millions
Balance at January 1		$2.0			$2.4			$2.0
Additions for Tax Positions Related to the Current Year	0.1			0.1			0.5
Additions for Tax Positions Related to Prior Years	0.1			0.2			0.7
Reductions for Tax Positions Related to Prior Years	(0.1		)	(0.3		)	(0.7		)
Lapse of Statute	(0.4		)	(0.4		)	(0.1		)
Balance as of December 31		$1.7			$2.0			$2.4

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, 2017, included $0.8 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2017, we had no accrued interest (none as of December 31, 2016, and 2015) 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 2017 (immaterial in 2016, and in 2015). There were no penalties recognized in 2017, 2016 or 2015. 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 2013 or state examination for years before 2012.

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2017

Reclassifications Out of Accumulated Other Comprehensive Income (Loss) [Abstract]

Reclassifications 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 securities, defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits, and gains and losses on derivatives accounted for as cash flow hedges.

NOTE 14. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

Changes in accumulated other comprehensive loss, net of tax, for the years ended December 31, 2017, 2016 and 2015, were as follows:



	Unrealized Gain (Loss) on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items (a)		Gain (Loss) on Cash Flow Hedge	Total
Millions
Balance as of December 31, 2014	$(0.3)		$(20.7)		$(0.1)	$(21.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.4	)	(4.3	)	0.1	(4.6	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1	)	1.3		—	1.2
Net Other Comprehensive Income (Loss)	(0.5	)	(3.0	)	0.1	(3.4	)
Balance as of December 31, 2015	(0.8	)	(23.7	)	—	(24.5	)
Other Comprehensive Income (Loss) Before Reclassifications	—		(4.1	)	—	(4.1	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.2	)	0.6		—	0.4
Net Other Comprehensive Income (Loss)	(0.2	)	(3.5	)	—	(3.7	)
Balance as of December 31, 2016	(1.0	)	(27.2	)	—	(28.2	)
Other Comprehensive Income (Loss) Before Reclassifications	1.1		3.9		—	5.0
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.2	)	0.8		—	0.6
Net Other Comprehensive Income (Loss)	0.9		4.7		—	5.6
Balance as of December 31, 2017	$(0.1)		$(22.5)		—	$(22.6)


(a)	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 15. Pension and Other Postretirement Benefit Plans.)

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2017

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 $1.7 million in cash to the plans in 2017 ($6.3 million in 2016; none in 2015). We also contributed approximately 0.2 million shares of ALLETE common stock to the plans in 2017, which had an aggregate value of $13.5 million when contributed (none in 2016; none in 2015). We also have a defined contribution RSOP covering substantially all employees. The 2017 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $11.0 million ($9.2 million for the 2016 plan year; $9.0 million for the 2015 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 does not allow further crediting of service to the plan and is closed to new participants. The Minnesota Power union defined benefit pension plan is also closed to new participants.

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

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to require employees to be at least age 55 with 10 years of participation in the plan. In 2014, our postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015. 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 2017, no contributions were made to the VEBAs (none in 2016; none in 2015) and no contributions were made to the grantor trusts (none in 2016; none in 2015).

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 8, 2018, we contributed $15.0 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 2018, and we do not expect to make any contributions to the defined benefit postretirement health and life plans in 2018.

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

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



Pension Obligation and Funded Status
As of December 31	2017			2016
Millions
Accumulated Benefit Obligation		$745.4			$698.8
Change in Benefit Obligation
Obligation, Beginning of Year		$743.3			$709.8
Service Cost	10.2			8.1
Interest Cost	32.5			33.2
Actuarial Loss	44.8			12.4
Benefits Paid	(51.0		)	(44.5		)
Participant Contributions	13.4			24.3
Obligation, End of Year		$793.2			$743.3
Change in Plan Assets
Fair Value, Beginning of Year		$557.5			$521.3
Actual Return on Plan Assets	91.6			48.8
Employer Contribution (a)	30.1			31.9
Benefits Paid	(51.0		)	(44.5		)
Fair Value, End of Year		$628.2			$557.5
Funded Status, End of Year	$(165.0)			$(185.8)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.4)			$(1.4)
Non-Current Liabilities	$(163.6)			$(184.4)


(a)	Includes Participant Contributions noted above.

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

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 $236.2 million as of December 31, 2017 (net loss of $250.4 million as of December 31, 2016).



Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2017	2016
Millions
Net Loss	$(236.2)	$(250.4)
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	71.2	64.6
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(165.0)	$(185.8)



Components of Net Periodic Pension Cost
Year Ended December 31	2017			2016			2015
Millions
Service Cost		$10.2			$8.1			$10.1
Interest Cost	32.5			33.2			29.9
Expected Return on Plan Assets	(42.4		)	(43.6		)	(40.7		)
Amortization of Loss	9.9			9.5			17.9
Amortization of Prior Service Cost	—			—			0.2
Net Pension Cost		$10.2			$7.2			$17.4



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2017		2016
Millions
Net (Gain) Loss	$(4.3)			$7.2
Amortization of Loss	(9.9	)	(9.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(14.2)		$(2.3)



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2017		2016
Millions
Projected Benefit Obligation		$793.2		$743.3
Accumulated Benefit Obligation		$745.4		$698.8
Fair Value of Plan Assets		$628.2		$557.5

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



Postretirement Health and Life Obligation and Funded Status
As of December 31	2017			2016
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$173.4			$160.2
Service Cost	4.4			3.9
Interest Cost	7.7			7.4
Actuarial Loss	15.5			11.9
Benefits Paid	(12.2		)	(13.1		)
Participant Contributions	3.1			3.1
Plan Amendments	(1.8		)	—
Obligation, End of Year		$190.1			$173.4
Change in Plan Assets
Fair Value, Beginning of Year		$154.3			$153.4
Actual Return on Plan Assets	24.5			9.6
Employer Contribution	1.3			1.3
Participant Contributions	3.1			3.1
Benefits Paid	(12.2		)	(13.1		)
Fair Value, End of Year		$171.0			$154.3
Funded Status, End of Year	$(19.1)			$(19.1)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$3.0			$1.4
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(21.0)			$(19.4)

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $19.2 million in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of December 31, 2017 ($17.6 million as of December 31, 2016).

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	2017		2016
Millions
Net Loss	$21.1		$19.8
Prior Service Credit	(4.6	)	(4.7	)
Total Unrecognized Postretirement Health and Life Cost	$16.5		$15.1



Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
As of December 31	2017		2016
Millions
Net Loss (a)	$(21.1)		$(19.8)
Prior Service Credit	4.6		4.7
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	(2.6	)	(4.0	)
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$(19.1)		$(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	2017			2016			2015
Millions
Service Cost		$4.4			$3.9			$4.3
Interest Cost	7.7			7.4			7.2
Expected Return on Plan Assets	(10.5		)	(11.2		)	(10.9		)
Amortization of Loss	0.3			0.2			0.4
Amortization of Prior Service Credit	(2.0		)	(2.9		)	(3.0		)
Net Postretirement Health and Life Credit	$(0.1)			$(2.6)			$(2.0)



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2017			2016
Millions
Net Loss		$1.6			$13.5
Prior Service Credit Arising During the Period	(1.8		)	—
Amortization of Prior Service Credit	2.0			2.9
Amortization of Loss	(0.3		)	(0.2		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$1.5			$16.2



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2018		$46.3		$9.2
2019		$46.2		$9.5
2020		$45.9		$9.6
2021		$45.8		$9.6
2022		$45.8		$9.6
Years 2023 – 2027		$228.0		$49.7

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, 2018, are as follows:



	Pension	Postretirement Health and Life
Millions
Net Loss	$12.0	$0.7
Prior Service Credit	—	(1.8	)
Total Pension and Postretirement Health and Life Cost (Credit)	$12.0	$(1.1)

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



Assumptions Used to Determine Benefit Obligation
As of December 31	2017	2016
Discount Rate
Pension	3.81 - 3.96%	4.53%
Postretirement Health and Life	3.86%	4.57%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	5.00 - 6.73%	5.00 - 7.00%
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	2017	2016	2015
Discount Rate	4.53 - 4.57%	4.72 - 4.73%	4.30 - 4.33%
Expected Long-Term Return on Plan Assets
Pension	7.50%	8.00%	8.00%
Postretirement Health and Life	6.00 - 7.50%	6.40 - 8.00%	6.40 - 8.00%
Rate of Compensation Increase	3.70 - 4.30%	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, 2017, 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		$1.9		($1.5	)
Effect on Postretirement Health and Life Obligation		$23.4		($19.3	)



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2017		2016		2017		2016
Equity Securities	53	%	49	%	64	%	60	%
Debt Securities	38	%	39	%	31	%	34	%
Private Equity	5	%	7	%	5	%	6	%
Real Estate	4	%	5	%	—		—
	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, 2017 (no shares as of December 31, 2016).

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, 2017:



Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	56	%	60	%
Debt Securities	35	%	37	%
Real Estate	9	%	3	%
	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Fair Value

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 various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.

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. This category includes various bonds and non-public funds whose underlying investments may be Level 1 or Level 2 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 private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

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

Fair Value (Continued)

Pension Fair Value



	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
Debt Securities:
Fixed Income	—		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)



	Fair Value as of December 31, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$94.6	—		—			$94.6
U.S. Mid-cap Growth (a)	—			$44.8	—		44.8
U.S. Small-cap (a)	—		45.0		—		45.0
International	46.7		42.3		—		89.0
Debt Securities:
Fixed Income	—		200.1		—		200.1
Cash and Cash Equivalents	17.8		—		—		17.8
Private Equity Funds	—		—			$40.6	40.6
Real Estate	—		—		25.6		25.6
Total Fair Value of Assets		$159.1		$332.2		$66.2		$557.5

(a)

The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1), mutual funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, to achieve the returns of the U.S. Equity Securities Mid-cap Growth and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2015		$43.3			$28.9
Actual Return on Plan Assets	5.0			2.3
Purchases, Sales, and Settlements – Net	(7.7		)	(5.6		)
Balance as of December 31, 2016		$40.6			$25.6

Postretirement Health and Life Fair Value



	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
Debt Securities:
Mutual Funds	49.8		—		—		49.8
Fixed Income	—			$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



	Fair Value as of December 31, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$27.9	—		—			$27.9
U.S. Mid-cap Growth	20.7		—		—		20.7
U.S. Small-cap	14.0		—		—		14.0
International	27.9		—		—		27.9
Debt Securities:
Mutual Funds	48.6		—		—		48.6
Fixed Income	—			$4.6	—		4.6
Cash and Cash Equivalents	1.1		—		—		1.1
Private Equity Funds	—		—			$9.5	9.5
Total Fair Value of Assets		$140.2		$4.6		$9.5		$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, 2015		$12.0
Actual Return on Plan Assets	1.4
Purchases, Sales, and Settlements – Net	(3.9		)
Balance as of December 31, 2016		$9.5

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

Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2017

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. In 1990, the ESOP issued a $75.0 million note to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our common stock. The note matured in December 2015. The ESOP shares were initially pledged as collateral for the debt. As the debt was repaid, shares were released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares were released from collateral, we reported compensation expense equal to the current market price of the shares less dividends on allocated shares. The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings. Future ESOP employer allocations will be funded with contributions paid in either cash or the issuance of ALLETE common stock at the Company’s discretion. ESOP compensation expense was $11.0 million in 2017 ($9.2 million in 2016; $9.0 million in 2015).

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. ESOP shares are included in earnings per share computations after they are allocated to participants.



As of December 31	2017	2016	2015
Millions
ESOP Shares
Allocated	1.4	1.6	1.8
Unallocated	—	—	—
Total	1.4	1.6	1.8
Fair Value of Unallocated Shares	—	—	—

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 1.0 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.8 million of these shares remain available for issuance as of December 31, 2017.

The following types of share-based awards were outstanding in 2017, 2016 or 2015:

Non-Qualified Stock Options. 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 three 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. Stock options have not been granted since 2008 and none were outstanding as of December 31, 2017.

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 plan, 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 units plan, 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. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards.

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	2017		2016		2015
Millions
Performance Shares		$2.1		$1.8		$1.8
Restricted Stock Units	1.0		0.8		0.8
Total Share-Based Compensation Expense		$3.1		$2.6		$2.6
Income Tax Benefit		$0.9		$1.1		$1.1

There were no capitalized share-based compensation costs during the years ended December 31, 2017, 2016 or 2015.

As of December 31, 2017, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $2.4 million and $1.0 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options.



	2017				2016				2015
	Number of Options		Weighted-Average Exercise Price		Number of Options		Weighted-Average Exercise Price		Number of Options		Weighted-Average Exercise Price
Outstanding as of January 1	4,357			$40.29	39,654			$44.39	66,279			$44.39
Exercised	(4,357	)		$40.29	(35,297	)		$44.89	(24,456	)		$44.52
Forfeited	—		—		—		—		(2,169	)		$42.93
Outstanding as of December 31	—		—		4,357			$40.29	39,654			$44.39
Exercisable as of December 31	—		—		4,357			$40.29	39,654			$44.39

Cash received from non-qualified stock options exercised was $0.3 million in 2017. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.1 million during 2017 ($0.5 million in 2016; $0.2 million in 2015).

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



	2017				2016				2015
	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	127,580			$52.56	119,540			$52.72	119,635			$48.26
Granted (a)	50,729			$62.90	57,189			$52.43	43,583			$58.95
Unearned Grant Award	(40,801	)		$46.27	(42,126	)		$52.70	(36,670	)		$45.41
Forfeited	(9,610	)		$58.29	(7,023	)		$53.45	(7,008	)		$53.49
Non-vested as of December 31	127,898			$58.23	127,580			$52.56	119,540			$52.72

(a) Shares granted include accrued dividends.

There were 35,894 performance shares granted in January 2018 for the three-year performance period ending in 2020. 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 $2.9 million. There were 58,293 performance shares awarded in February 2018. The grant date fair value of the shares awarded was $3.5 million.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock-Based Compensation (Continued)

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



	2017				2016				2015
	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	54,728			$51.79	57,694			$49.86	53,888			$44.47
Granted (a)	21,241			$62.20	20,351			$50.25	26,702			$54.81
Awarded	(17,281	)		$49.72	(19,661	)		$44.33	(19,464	)		$41.44
Forfeited	(3,440	)		$56.00	(3,656	)		$52.87	(3,432	)		$51.52
Available as of December 31	55,248			$56.18	54,728			$51.79	57,694			$49.86

(a) Shares granted include accrued dividends.

There were 14,569 restricted stock units granted in January 2018 for the vesting period ending in 2020. The grant date fair value of the restricted stock units granted was $1.1 million. There were 12,766 restricted stock units awarded in February 2018. The grant date fair value of the shares awarded was $0.7 million.

Business Segments

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Business Segments [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 other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

NOTE 17. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2017			2016			2015
Millions
Operating Revenue
Regulated Operations		$1,063.8			$1,000.7			$991.2

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	80.5			80.5			262.1
U.S. Water Services	151.8			137.5			119.8

Corporate and Other	123.2			121.0			113.3
Total Operating Revenue		$1,419.3			$1,339.7			$1,486.4
Net Income (Loss) Attributable to ALLETE (b)(c)
Regulated Operations		$128.4			$135.5			$131.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	41.5			13.4			29.9
U.S. Water Services	10.7			1.5			0.9

Corporate and Other	(8.4		)	4.9			(21.3		)
Total Net Income Attributable to ALLETE		$172.2			$155.3			$141.1
Depreciation and Amortization
Regulated Operations		$132.6			$154.3			$135.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	23.4			22.3			18.7
U.S. Water Services	9.8			8.9			7.3

Corporate and Other	11.7			10.3			8.9
Total Depreciation and Amortization		$177.5			$195.8			$170.0
Operating Expenses – Other (d)
ALLETE Clean Energy	—				$3.3		—
Corporate and Other	$(0.7)			(13.6		)	$36.3
Total Operating Expenses – Other	$(0.7)			$(10.3)			$36.3
Interest Expense (c)
Regulated Operations	$57.0			$52.1			$53.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	4.2			5.8			3.3
U.S. Water Services	1.6			1.7			1.4

Corporate and Other	10.3			14.5			8.6

Eliminations	(5.3		)	(3.8		)	(2.3		)
Total Interest Expense	$67.8			$70.3			$64.9
Equity Earnings in ATC
Regulated Operations	$22.5			$18.5			$16.3


(a)	Includes the construction and sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities for $197.7 million in 2015.

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

NOTE 17. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2017			2016		2015
Millions
Income Tax Expense (Benefit) (a)
Regulated Operations (b)		$27.2			$5.9		$24.4

Energy Infrastructure and Related Services
ALLETE Clean Energy	(14.2		)	8.1		21.0
U.S. Water Services	(7.8		)	1.4		0.9

Corporate and Other (b)	9.5			4.4		(21.0		)
Total Income Tax Expense		$14.7			$19.8		$25.3

(a)

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.)

(b)

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.)



As of December 31	2017		2016
Millions
Assets
Regulated Operations (a)	$3,886.6		$3,823.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	600.5		566.0
U.S. Water Services	292.4		264.1

Corporate and Other	300.5		222.9
Total Assets (a)		$5,080.0		$4,876.9
Capital Expenditures
Regulated Operations	$177.1		$121.8

Energy Infrastructure and Related Services
ALLETE Clean Energy	56.1		106.9
U.S. Water Services	4.4		3.7

Corporate and Other	28.9		15.4
Total Capital Expenditures		$266.5		$247.8


(a)	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited) [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED)

Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.



Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2017
Operating Revenue		$365.6		$353.3		$362.5		$337.9
Operating Income		$72.6		$55.0		$69.0		$33.2
Net Income Attributable to ALLETE		$49.0		$36.9		$44.9		$41.4
Earnings Per Share of Common Stock
Basic		$0.97		$0.73		$0.88		$0.81
Diluted		$0.97		$0.72		$0.88		$0.81
2016
Operating Revenue		$333.8		$314.8		$349.6		$341.5
Operating Income		$66.8		$42.2		$53.4		$61.1
Net Income Attributable to ALLETE		$45.9		$24.8		$40.3		$44.3
Earnings Per Share of Common Stock
Basic		$0.93		$0.50		$0.82		$0.89
Diluted		$0.93		$0.50		$0.81		$0.89
2015
Operating Revenue		$320.0		$323.3		$462.5		$380.6
Operating Income		$56.4		$39.5		$85.2		$29.6
Net Income Attributable to ALLETE		$39.9		$22.5		$60.4		$18.3
Earnings Per Share of Common Stock
Basic		$0.85		$0.46		$1.24		$0.37
Diluted		$0.85		$0.46		$1.23		$0.37

Schedule II

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II [Text Block]

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves



	Balance at Beginning of Period		Additions			Deductions from Reserves (a)		Balance at End of Period
	Balance at Beginning of Period		Charged to Income		Other Charges	Deductions from Reserves (a)		Balance at End of Period
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2015 Trade Accounts Receivable		$1.1		$1.6	—		$1.7		$1.0
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
2016 Trade Accounts Receivable		$1.0		$4.1	—		$2.0		$3.1
Finance Receivables – Long-Term		$0.6	—		—		$0.6	—
2017 Trade Accounts Receivable		$3.1	$0.8		—		$1.8		$2.1
Finance Receivables – Long-Term	—		—		—	—		—
Deferred Asset Valuation Allowance
2015 Deferred Tax Assets		$22.1	$9.5		—	—			$31.6
2016 Deferred Tax Assets		$31.6	$11.4		—	—			$43.0
2017 Deferred Tax Assets		$43.0		$17.0	—	—			$60.0


(a)	Includes uncollectible accounts written-off.

Operations and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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. We present three reportable segments: Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Cash and Cash Equivalents [Policy Text Block]	We consider all investments purchased with original maturities of three months or less to be cash equivalents.
Accounts Receivable [Policy Text Block]	Accounts receivable are reported on the Consolidated Balance Sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific situations and such other factors that, in our judgment, deserve recognition in estimating losses.
Long-Term Finance Receivables [Policy Text Block]	Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals.
Available-for-Sale Securities [Policy Text Block]	Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as share price trends and the impact of overall market conditions. (See New Accounting Pronouncements and 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 and ALLETE Clean Energy segments are carried at an average cost or first-in, first-out basis. Inventories in our U.S. Water Services segment and Corporate and Other operations 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.) NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) Property, Plant and Equipment (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. 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. 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.
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.) Non-Qualified Stock Options. 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 three 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. Stock options have not been granted since 2008 and none were outstanding as of December 31, 2017. 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 plan, 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 units plan, 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. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards. 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.
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. 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 2017, 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. Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. The Company calculates the excess of the reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. 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 1 year to approximately 20 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. 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. 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.
Environmental Liabilities [Policy Text Block]	We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.
Revenue Recognition [Policy Text Block]	Regulated Operations utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for services provided but not yet billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission, renewable, and environmental improvement expenditures. Previously, fuel and purchased power expense was deferred to match the period in which the revenue for fuel and purchased power expense was billed to customers with the deferred fuel costs recognized as a regulatory asset. 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 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 a result of the MPUC hearing, fuel and purchased power costs above or below the base levels in rate schedules are no longer deferred. Revenue from cost recovery riders (transmission, renewable and environmental improvement) is accounted for in accordance with GAAP for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory authority, the order allows automatic adjustment of future rates, the amount of the 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. Revenue recognized using the alternative revenue program guidance is included in Operating Revenue – Utility on the Consolidated Statement of Income and Regulatory Assets on the Consolidated Balance Sheet until it is subsequently collected from customers. Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue – Utility and net purchases in Fuel, Purchased Power and Gas – Utility expense on the Consolidated Statement of Income. ALLETE Clean Energy recognizes revenue from the sale of energy from PSAs under various durations. Revenue is recognized when delivered to an agreed upon point or production is curtailed at the request of its customers at specified prices. As part of its acquisitions of wind energy facilities, ALLETE Clean Energy has assumed various PSAs that were above or below estimated market prices at the time of acquisition and amortizes the resulting differences between contract prices and estimated market prices to Operating Revenue – Non-utility on the Consolidated Statement of Income. Revenue from the construction and sale of wind energy facilities to others will be recognized at a point in time, or over time, as performance obligations are satisfied based on the terms of each specific agreement. U.S. Water Services recognizes revenue from the sale of products when the earnings process is complete. This generally occurs when products are shipped to the customer in accordance with the contract or purchase order, ownership and risk of loss have passed to the customer, collectibility is reasonably assured, and pricing is fixed and determinable. Revenue from services is recognized as the services are performed. Corporate and Other BNI Energy recognizes coal sales when delivered at the cost of production plus a specified profit per ton of coal delivered. ALLETE Properties records full profit recognition on sales of real estate upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. Certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.
Revenue from Cost Recovery Riders [Policy Text Block]	Revenue from cost recovery riders (transmission, renewable and environmental improvement) is accounted for in accordance with GAAP for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory authority, the order allows automatic adjustment of future rates, the amount of the 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. Revenue recognized using the alternative revenue program guidance is included in Operating Revenue – Utility on the Consolidated Statement of Income and Regulatory Assets on the Consolidated Balance Sheet until it is subsequently collected from customers.
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]	Under ASC 740, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. ASC 740 requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, as of the date of enactment, the Company’s deferred income tax assets and liabilities were remeasured based upon the new tax rate. As provided for under SAB 118, the Company has not estimated the impact for items for which it cannot predict, such as guidance that has not yet been provided, or for which federal or state regulatory treatment is still uncertain. The determination of the impact of the income tax effects of these types of items will occur when more information is available to the Company. ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns. We account for income taxes using the liability method in accordance with GAAP for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.
Income Taxes, Effects of Regulation [Policy Text Block]	Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. 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 o
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. 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. 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 the 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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method. 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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method. 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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method. 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 the second quarter of 2017, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis. 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 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method. The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to income tax liabilities; subsequent adjustments could impact the amount of goodwill recorded. 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 Simplifying the Measurement of Inventory. In 2015, the FASB issued an accounting standards update which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance was adopted in the first quarter of 2017 and did not have a material impact on our Consolidated Financial Statements. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued guidance to simplify the accounting for share-based payment transactions by requiring all excess tax benefits and deficiencies to be recognized in income tax expense or benefit in earnings, thus eliminating the requirement to classify the excess tax benefit and deficiencies as additional paid-in capital. Under the new guidance, an entity makes an accounting policy election to either estimate the expected forfeiture awards or account for forfeitures as they occur. This accounting guidance was adopted in the first quarter of 2017. The adoption of this guidance is expected to result in a less than $1 million impact to income tax expense (benefit) annually. Clarifying the Definition of a Business. In January 2017, the FASB issued clarifying guidance on the definition of a business and provided additional guidance to assist with evaluating whether transactions are to be accounted for as an acquisition or disposal of a group of assets or a business. The clarifying guidance will also impact other areas including the accounting for goodwill and consolidation. This accounting guidance was adopted in the first quarter of 2017 and did not have an impact on our Consolidated Financial Statements. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) New Accounting Pronouncements (Continued) Stock Compensation: Scope of Modification Accounting. In May 2017, the FASB issued additional clarifying guidance regarding circumstances where changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting under ASC 718. The guidance provides specific situations that would be excluded from effects of a modification including if the fair value, vesting conditions, and classification are the same before and after modification. The amendments in this update will be applied prospectively to awards modified on or after adoption. This accounting guidance was adopted by the Company in the second quarter of 2017 and did not have an impact on our Consolidated Financial Statements. 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. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued guidance to improve the presentation of net periodic pension and postretirement benefit costs. Under the revised guidance of ASC 715, an entity shall 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. The standard will be applied retrospectively for income statement presentation, and prospectively for capitalization of service cost components. We do not expect there to be a material impact on the Consolidated Financial Statements with the adoption of the updated guidance which is effective for the Company beginning in the first quarter of 2018. 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 in exchange for those goods or services. The guidance also 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 are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. As of December 31, 2017, the Company has reviewed all of its revenue streams and contracts for its regulated, energy infrastructure and related services, and corporate and other businesses, completing the evaluations of the impact of this new guidance. Based on these evaluations, the Company has determined the new guidance does not materially alter the amount or timing of revenue recognition from the current methodology nor does it have a material transition adjustment upon adoption. Additionally, management does not expect the recognition of any assets from the costs to obtain a contract. Management continues to draft and refine the additional disclosures needed to meet the requirements of the new standard following adoption. The Company will adopt and implement the new guidance on a modified retrospective basis which requires application of standards to all contracts with customers effective January 1, 2018, with the cumulative impact on contracts with performance obligations not yet satisfied as of December 31, 2017, recognized as an adjustment to Retained Earnings on the Consolidated Balance Sheet. Leases. In February 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, 2017, ALLETE expects to make $79.9 million in minimum lease payments due in future years (undiscounted). The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. We are currently evaluating the impact of the revised lease guidance on our Consolidated Financial Statements. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) New Accounting Pronouncements (Continued) Financial Instruments. In January 2016, the FASB issued an accounting standard update which requires entities to measure their 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 updated guidance is effective for the Company beginning in the first quarter of 2018 and will result in a cumulative-effect adjustment to Retained Earnings on the Consolidated Balance Sheet in the fiscal year of adoption. We have performed a preliminary evaluation of the impact of this update, and based on that evaluation, we do not expect the adoption of the update to have a material impact on our Consolidated Financial Statements. Classification of Certain Cash Receipts and Cash Payments. In August 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. This accounting guidance is effective for the Company beginning in the first quarter of 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows. Statement of Cash Flows: Restricted Cash. In November 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 accounting guidance is effective for the Company beginning in the first quarter of 2018 and will be applied retrospectively to all periods presented. The guidance will result in changes to the Company’s Consolidated Statement of Cash Flows such that restricted cash amounts will be included in the beginning-of-period and end‑of‑period cash and cash equivalents totals when adopted for our fiscal year beginning January 1, 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.
Asset Retirement Obligations [Policy Text Block]	We recognize, at fair value, obligations associated with the retirement of certain tangible, long‑lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (AROs) relate primarily to the decommissioning of our coal-fired and wind energy facilities, and land reclamation at BNI Energy. AROs are included in Other Non-Current Liabilities on the Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives. Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal liabilities have not been recognized because they are considered immaterial to our Consolidated Financial Statements. Long-standing ratemaking practices approved by applicable state and federal regulatory authorities have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-AROs. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with GAAP for AROs.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities 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
Equity Method Investments [Policy Text Block]	We account for our investment in ATC under the equity method of accounting. The Company assesses our investment in ATC for impairment whenever events or changes in circumstances indicate that the carrying amount of our investment in ATC may not be recoverable.
Land Inventory [Policy Text Block]	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. Land values are reviewed for indicators of impairment on a quarterly basis and no impairment was recorded in 2017 (none in 2016; $36.3 million in 2015).
Fair Value Measurement [Policy Text Block]	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. 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. 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. 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. 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).
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 our capacity and energy payments.
Earnings Per Share [Policy Text Block]	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, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). No options to purchase shares of common stock were excluded from the computation of diluted earnings per share in 2017, 2016 and 2015.
Pension and Other Postretirement Benefit Plans [Policy Text Block]	According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. Accounting for defined benefit pension and other postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset (regulatory liability) on the Consolidated Balance Sheet, in accordance with the accounting standards for the effect of certain types of regulation applicable to our Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other operations are recognized in accumulated other comprehensive income. 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. 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.
Employee Stock Ownership Plan [Policy Text Block]	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. ESOP shares are included in earnings per share computations after they are allocated to participants. The ESOP shares were initially pledged as collateral for the debt. As the debt was repaid, shares were released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares were released from collateral, we reported compensation expense equal to the current market price of the shares less dividends on allocated shares. The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings. Future ESOP employer allocations will be 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, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Supplemental Statement of Cash Flow Information [Table Text Block]

Supplemental Statement of Cash Flow Information.



Consolidated Statement of Cash Flows
Year Ended December 31	2017		2016		2015
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$64.5		$68.2		$59.0
Cash Paid During the Period for Income Taxes		$0.4		$0.5		$0.4
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	$67.2		$(22.0)		$(40.6)
Capitalized Asset Retirement Costs	$(15.6)			$3.7	$12.4
Camp Ripley Solar Financing	—		$15.0		—
AFUDC–Equity		$1.2		$2.1		$3.3
ALLETE Common Stock Contributed to Pension Plans		$13.5	—		—
Contingent Consideration	—		—			$35.7
ALLETE Common Stock Received for Land Inventory	—			$8.0	—
Long-Term Finance Receivable for Land Inventory	—			$12.0	—

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2017		2016
Millions
Trade Accounts Receivable
Billed		$112.6		$106.5
Unbilled	24.6		19.1
Less: Allowance for Doubtful Accounts	2.1		3.1
Total Accounts Receivable		$135.1		$122.5

Inventories – Net [Table Text Block]



Inventories – Net
As of December 31	2017			2016
Millions
Fuel (a)		$34.8			$43.9
Materials and Supplies	46.5			48.7
Raw Materials	2.8			2.9
Work in Progress	4.2			1.0
Finished Goods	8.3			8.6
Reserve for Obsolescence	(0.7		)	(0.9		)
Total Inventories – Net		$95.9			$104.2


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

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets
As of December 31	2017		2016
Millions
Deferred Fuel Adjustment Clause (a)	—			$18.6
Restricted Cash (b)		$2.6	2.2
Other	35.0		19.5
Total Prepayments and Other Current Assets		$37.6		$40.3


(a)	At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017.


(b)	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and collateral deposits required for U.S. Water Services’ standby letters of credit.

Other Non-Current Assets [Table Text Block]



Other Non-Current Assets
As of December 31	2017		2016
Millions
Contract Payment (a)		$27.5		$29.6
Finance Receivable (b)	11.0		11.5
Restricted Cash (c)	8.6		8.6
Other	60.6		56.8
Total Other Non-Current Assets		$107.7		$106.5


(a)	Contract Payment includes a payment made to Cliffs as part of a long-term PSA between Minnesota Power and Silver Bay Power. The contract payment is being amortized over the term of the PSA. (See Note 11. Commitments, Guarantees and Contingencies.)

(b)


(c)	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.

Other Current Liabilities [Table Text Block]



Other Current Liabilities
As of December 31	2017		2016
Millions
PSAs		$24.5		$24.6
Other	58.7		49.1
Total Other Current Liabilities		$83.2		$73.7

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities
As of December 31	2017		2016
Millions
Asset Retirement Obligation		$122.7		$136.6
PSAs	89.5		113.8
Contingent Consideration (a)	5.4		25.0
Other	49.5		47.3
Total Other Non-Current Liabilities		$267.1		$322.7


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 6. Acquisitions and Note 9. Fair Value.)

Operating Expenses – Other [Table Text Block]



Operating Expenses – Other
Year Ended December 31	2017	2016			2015
Millions
Impairment of Real Estate (a)	—	—				$36.3
Impairment of Goodwill (b)	—		$3.3		—
Change in Fair Value of Contingent Consideration (c)	$(0.7)	(13.6		)	—
Total Operating Expenses – Other	$(0.7)	$(10.3)				$36.3


(a)	See Impairment of Long-Lived Assets.


(b)	See Goodwill and Intangible Assets.


(c)	See Note 9. Fair Value.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

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	2017			2016
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,523.7			$4,437.0
Construction Work in Progress	121.6			84.2
Accumulated Depreciation	(1,520.5		)	(1,426.1		)
Regulated Operations – Net	3,124.8			3,095.1
ALLETE Clean Energy
Property, Plant and Equipment in Service	482.5			472.3
Construction Work in Progress	144.9			101.0
Accumulated Depreciation	(60.8		)	(41.0		)
ALLETE Clean Energy – Net	566.6			532.3
U.S. Water Services
Property, Plant and Equipment in Service	24.8			19.5
Accumulated Depreciation	(10.4		)	(6.9		)
U.S. Water Services – Net	14.4			12.6
Corporate and Other (a)
Property, Plant and Equipment in Service	204.7			179.8
Construction Work in Progress	5.0			2.8
Accumulated Depreciation	(93.1		)	(81.4		)
Corporate and Other – Net	116.6			101.2
Property, Plant and Equipment – Net		$3,822.4			$3,741.2


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



Estimated Useful Lives of Property, Plant and Equipment
Regulated Operations		ALLETE Clean Energy (a)	5 to 35 years
Generation	5 to 50 years	U.S. Water Services	3 to 39 years
Transmission	44 to 67 years	Corporate and Other	3 to 50 years
Distribution	18 to 65 years


(a)	ALLETE Clean Energy’s Property, Plant and Equipment consists primarily of WTGs with estimated useful lives ranging from 30 years to 35 years.

Asset Retirement Obligations [Table Text Block]



Asset Retirement Obligations
Millions
Obligation as of December 31, 2015		$131.4
Accretion	8.0
Liabilities Settled	(6.5		)
Revisions in Estimated Cash Flows	3.7
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

Jointly-Owned Facilities and Projects (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017
Boswell Unit 4		$668.2		$222.8		$8.2	80
CapX2020 Projects	101.0		8.4		—		9.3 - 14.7
Total		$769.2		$231.2		$8.2
As of December 31, 2016
Boswell Unit 4		$668.1		$211.2		$8.1	80
CapX2020 Projects	101.2		5.9		—		9.3 - 14.7
Total		$769.3		$217.1		$8.1

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2017

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2017		2016
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause	—			$18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	$220.3		226.1
Income Taxes (c)(d)	112.8		33.8
Asset Retirement Obligations (e)	29.6		26.0
Manufactured Gas Plant (f)	8.1		1.0
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program (g)	3.3		4.0
Cost Recovery Riders (h)	—		30.5
Other	5.6		3.7
Total Non-Current Regulatory Assets	384.7		330.1
Total Regulatory Assets		$384.7		$348.7
Non-Current Regulatory Liabilities
Income Taxes (d)		$411.2		$19.1
Wholesale and Retail Contra AFUDC (i)	57.9		56.8
Provision for Interim Rate Refund (j)	23.7		—
Plant Removal Obligations	20.3		19.1
North Dakota Investment Tax Credits (k)	14.1		28.2
Cost Recovery Riders (h)	2.2		—
Other	2.6		2.6
Total Non-Current Regulatory Liabilities		$532.0		$125.8


(a)	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. (See 2016 Minnesota General Rate Case.)

(b)


(c)	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

(d)


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


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


(g)	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.

(h)


(i)	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.


(j)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $8.6 million of EITE discounts that will be offset against interim rate refunds. (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(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 fillings as the tax credits are utilized.

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2017		2016
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause	—			$18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	$220.3		226.1
Income Taxes (c)(d)	112.8		33.8
Asset Retirement Obligations (e)	29.6		26.0
Manufactured Gas Plant (f)	8.1		1.0
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program (g)	3.3		4.0
Cost Recovery Riders (h)	—		30.5
Other	5.6		3.7
Total Non-Current Regulatory Assets	384.7		330.1
Total Regulatory Assets		$384.7		$348.7
Non-Current Regulatory Liabilities
Income Taxes (d)		$411.2		$19.1
Wholesale and Retail Contra AFUDC (i)	57.9		56.8
Provision for Interim Rate Refund (j)	23.7		—
Plant Removal Obligations	20.3		19.1
North Dakota Investment Tax Credits (k)	14.1		28.2
Cost Recovery Riders (h)	2.2		—
Other	2.6		2.6
Total Non-Current Regulatory Liabilities		$532.0		$125.8


(a)	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. (See 2016 Minnesota General Rate Case.)

(b)


(c)	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

(d)


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


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


(g)	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.

(h)


(i)	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.


(j)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $8.6 million of EITE discounts that will be offset against interim rate refunds. (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(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 fillings as the tax credits are utilized.

Investment in ATC (Tables)

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

ALLETE's Investment in ATC [Table Text Block]



ALLETE’s Investment in ATC
Year Ended December 31	2017			2016
Millions
Equity Investment Beginning Balance		$135.6			$124.5
Cash Investments	7.8			5.4
Equity in ATC Earnings	22.5			18.5
Distributed ATC Earnings	(19.3		)	(12.8		)
Remeasurement of Deferred Income Taxes (a)	(27.9		)	—
Equity Investment Ending Balance		$118.7			$135.6


(a)	Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2017		2016
Millions
Current Assets		$87.7		$75.8
Non-Current Assets	4,598.9		4,312.9
Total Assets		$4,686.6		$4,388.7
Current Liabilities		$767.2		$495.1
Long-Term Debt	1,790.6		1,865.3
Other Non-Current Liabilities	240.3		271.5
Members’ Equity	1,888.5		1,756.8
Total Liabilities and Members’ Equity		$4,686.6		$4,388.7



Income Statement Data
Year Ended December 31	2017		2016		2015
Millions
Revenue		$721.6		$650.8		$615.8
Operating Expense	344.9		322.5		319.3
Other Expense	104.1		95.5		96.1
Net Income		$272.6		$232.8		$200.4
ALLETE’s Equity in Net Income		$22.5		$18.5		$16.3

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

Tonka Water [Member]

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]

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.

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



Millions
Assets Acquired
Cash and Cash Equivalents		$0.9
Accounts Receivable	16.8
Inventories (a)	13.4
Other Current Assets (b)	5.3
Property, Plant and Equipment	10.6
Intangible Assets (c)	83.0
Goodwill (d)	122.9
Other Non-Current Assets	0.2
Total Assets Acquired		$253.1
Liabilities Assumed
Current Liabilities		$19.2
Non-Current Liabilities	31.6
Total Liabilities Assumed		$50.8
Net Identifiable Assets Acquired		$202.3


(a)	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of Sales within one year from the acquisition date.


(b)	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog was recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for standby letters of credit.


(c)	Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 7. Goodwill and Intangible Assets.)


(d)	For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill.

Chanarambie/Viking [Member]

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



Millions
Assets Acquired
Current Assets		$4.8
Property, Plant and Equipment	103.0
Other Non-Current Assets (a)	1.0
Total Assets Acquired		$108.8
Liabilities Assumed
Current Liabilities (b)		$6.7
PSAs	49.0
Non-Current Liabilities	5.1
Total Liabilities Assumed		$60.8
Net Identifiable Assets Acquired		$48.0


(a)	Included in Other Non-Current Assets was $0.3 million of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Current Liabilities included $5.9 million related to the current portion of PSAs.

Armenia Mountain [Member]

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



Millions
Assets Acquired
Current Assets (a)		$9.0
Property, Plant and Equipment	156.2
Other Non-Current Assets (b)	14.4
Total Assets Acquired		$179.6
Liabilities Assumed
Current Liabilities		$2.9
Long-Term Debt Due Within One Year	5.9
Long-Term Debt	55.0
Other Non-Current Liabilities	4.7
Total Liabilities Assumed		$68.5
Net Identifiable Assets Acquired		$111.1


(a)	Included in Current Assets was $1.0 million related to the current portion of PSAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.


(b)	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PSAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

A and W Technologies [Member]

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



Millions
Assets Acquired
Current Assets		$1.0
Property, Plant and Equipment	0.1
Intangible Assets (a)	3.9
Goodwill (b)	4.4
Total Assets Acquired		$9.4
Liabilities Assumed
Current Liabilities		$0.1
Total Liabilities Assumed		$0.1
Net Identifiable Assets Acquired		$9.3


(a)	Intangible Assets include customer relationships and non-compete agreements. (See Note 7. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill.

Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

The following table summarizes changes to goodwill by reportable segment:



	ALLETE Clean Energy			U.S. Water Services		Total
Millions
Balance as of December 31, 2015		$3.3			$127.3		$130.6
Acquired Goodwill (a)	—			3.9		3.9
Impairment Charge (b)	(3.3		)	—		(3.3		)
Balance as of December 31, 2016	—			131.2		131.2
Acquired Goodwill (a)	—			16.9		16.9
Other Adjustments (c)	—			0.2		0.2
Balance as of December 31, 2017	—				$148.3		$148.3


(a)	See Note 6. Acquisitions.

(b)


(c)	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition.

Schedule of Intangible Assets [Table Text Block]

The following table summarizes changes to intangible assets, net, for the year ended December 31, 2017:



	December 31, 2016		Additions (a)		Amortization	December 31, 2017
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$59.3	—		$(4.6)		$54.7
Developed Technology and Other (b)	6.3			$0.9	(0.9)	6.3
Total Definite-Lived Intangible Assets	65.6		0.9		(5.5)	61.0
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$82.2		$0.9	$(5.5)		$77.6


(a)	Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 6. Acquisitions.)


(b)	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, 2017

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.1	—		—			$7.1
Available-for-sale – Corporate and Governmental Debt Securities	—			$11.7	—		11.7
Cash Equivalents	1.3		—		—		1.3
Total Fair Value of Assets		$8.4		$11.7	—			$20.1

Liabilities: (b)
Deferred Compensation	—			$16.0	—			$16.0
U.S. Water Services Contingent Consideration	—		—			$25.0	25.0
Total Fair Value of Liabilities	—			$16.0		$25.0		$41.0
Total Net Fair Value of Assets (Liabilities)		$8.4	$(4.3)		$(25.0)		$(20.9)


(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, 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.

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, 2015		$36.6
Accretion (a)	2.8
Payments	(0.8		)
Changes in Cash Flow Projections (b)	(13.6		)
Balance as of December 31, 2016		$25.0
Accretion (a)	0.8
Payments (c)	(19.7		)
Changes in Cash Flow Projections (c)	(0.7		)
Balance as of December 31, 2017		$5.4


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

(b)


(c)	Payments and changes in cash flow projections 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 the first half of 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, 2017	$1,513.3	$1,627.6
December 31, 2016	$1,569.1	$1,653.8

Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-term Debt [Table Text Block]



Long-Term Debt
As of December 31	2017			2016
Millions
First Mortgage Bonds
1.83% Series Due 2018		$50.0			$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
Unsecured Term Loan Variable Rate Due 2017	—			125.0
Senior Unsecured Notes 5.99% Due 2017	—			50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Unsecured Term Loan Variable Rate Due 2020	40.0			—
Armenia Mountain Senior Secured Notes 3.26% Due 2024	65.9			74.6
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			—
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0			15.0
Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037	69.1			61.2
Unamortized Debt Issuance Costs	(10.0		)	(11.0		)
Total Long-Term Debt	1,503.3			1,558.1
Less: Due Within One Year	64.1			187.7
Net Long-Term Debt		$1,439.2			$1,370.4

Commitments and Contingencies Disclosure [Abstract]

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://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 210
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-Paragraph 3
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Subparagraph (SX 210.4-08.(e),(f))
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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+ Details

Commitments, Guarantees and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017
Millions	2018		2019		2020		2021		2022		Thereafter
Coal, Rail and Shipping Contracts		$29.0		$1.8	—		—		—		—
Leasing Agreements		$14.2		$12.8		$9.5		$7.3		$6.1		$30.0
Long-term Service Agreements (a)		$11.0		$0.9	—		—			$1.0		$11.0
PPAs (b)		$104.5		$107.1		$115.0		$144.8		$144.7		$1,667.0


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

(b)

Minnesota Power has also entered into the following agreements for the purchase or sale of capacity and energy as of December 31, 2017:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Great River Energy
PPA 1	50 MW	Capacity / Energy	June 2016	May 2020	(a)
PPA 2	50 MW	Capacity	June 2016	May 2020	Fixed
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
Manitoba Hydro
PPA 1	(b)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	50 MW	Capacity / Energy	June 2015	May 2020	(c)
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
PPA 4 (d)	250 MW	Capacity / Energy	June 2020	May 2035	(e)
PPA 5 (d)	133 MW	Energy	(f)	(f)	Forward Market Prices
Minnkota Power	50 MW	Capacity / Energy	June 2016	May 2020	(g)
Oliver Wind I	(h)	Energy	December 2006	December 2031	Fixed
Oliver Wind II	(h)	Energy	December 2007	December 2032	Fixed
Shell Energy	50 MW	Energy	January 2017	December 2019	Fixed
TransAlta	(i)	Energy	January 2017	December 2019	Fixed
Tenaska (j)	(j)	Capacity / Energy	June 2020	June 2040	Fixed
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(k)
PSA 2	100 MW	Capacity	June 2016	May 2018	Fixed
PSA 3	50 MW	Capacity	June 2017	May 2019	Fixed
Minnkota Power	(l)	Capacity / Energy	June 2014	December 2026	(l)
Silver Bay Power	(m)	Energy	January 2017	December 2031	(n)


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


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


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


(d)	Agreements are subject to the construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. (See Great Northern Transmission Line.)


(e)	The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.


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


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


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


(i)	The energy purchased under the 50 MW PPA is during off-peak hours and the 100 MW PPA is during on-peak hours.


(j)	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota and is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired facility. (See Note 4. Regulatory Matters.)


(k)	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.

(l)

(m)


(n)	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, 2017

Equity [Abstract]

Summary of Common Stock [Table Text Block]



Summary of Common Stock	Shares		Equity
	Thousands		Millions
Balance as of December 31, 2014	45,929			$1,107.6
Employee Stock Purchase Plan	18		0.9
Invest Direct	383		19.0
Options and Stock Awards	43		8.6
Equity Issuance Program	1,289		69.9
Forward Sale Agreement and Issuance	1,413		65.4
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
Contributions to Pension	216		13.5
Balance as of December 31, 2017	51,117			$1,401.4

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
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
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
2015
Net Income Attributable to ALLETE		$141.1			$141.1
Average Common Shares	48.3		0.1	48.4
Earnings Per Share		$2.92			$2.92

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2017			2016			2015
Millions
Current Income Tax Expense (a)
Federal	—			—			—
State	$0.3			$0.4			$0.2
Total Current Income Tax Expense		$0.3			$0.4			$0.2
Deferred Income Tax Expense
Federal		$12.1			$12.0			$19.4
Federal – Remeasurement of Deferred Income Taxes (b)	(13.0		)	—			—
State	15.8			8.1			6.5
Investment Tax Credit Amortization	(0.5		)	(0.7		)	(0.8		)
Total Deferred Income Tax Expense		$14.4			$19.4			$25.1
Total Income Tax Expense		$14.7			$19.8			$25.3


(a)	For the years ended December 31, 2017, 2016 and 2015, 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. The federal and state NOLs will be carried forward to offset future taxable income.


(b)	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)

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	2017			2016			2015
Millions
Income Before Non-Controlling Interest and Income Taxes		$186.9			$175.6			$166.8
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$65.4			$61.5			$58.4
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	10.5			5.6			4.4
Regulatory Differences for Utility Plant	—			(0.1		)	(0.6		)
Production Tax Credits	(45.1		)	(41.5		)	(37.0		)
Change in Fair Value of Contingent Consideration	—			(3.8		)	—
Remeasurement of Deferred Income Taxes (a)	(13.0		)	—			—
Other	(3.1		)	(1.9		)	0.1
Total Income Tax Expense		$14.7			$19.8			$25.3


(a)	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)

Deferred Tax Assets and Liabilities [Table Text Block]



Deferred Income Tax Assets and Liabilities
As of December 31	2017			2016
Millions
Deferred Income Tax Assets
Employee Benefits and Compensation		$65.9			$104.6
Property Related	104.3			110.5
NOL Carryforwards	99.1			185.6
Tax Credit Carryforwards	294.3			227.4
Power Sales Agreements	35.0			59.3
Regulatory Liabilities	117.7			7.3
Other	33.3			46.9
Gross Deferred Income Tax Assets	749.6			741.6
Deferred Income Tax Asset Valuation Allowance	(60.0		)	(43.0		)
Total Deferred Income Tax Assets		$689.6			$698.6
Deferred Income Tax Liabilities
Property Related		$758.3			$1,039.6
Regulatory Asset for Benefit Obligations	61.4			91.9
Unamortized Investment Tax Credits	32.8			33.3
Partnership Basis Differences	34.9			50.9
Regulatory Assets	32.0			25.6
Other	0.7			11.9
Total Deferred Income Tax Liabilities		$920.1			$1,253.2
Net Deferred Income Taxes (a)		$230.5			$554.6


(a)	Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet. Additionally, see Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
As of December 31	2017	2016
Millions
Federal NOL Carryforwards (a)	$375.2		$485.3
Federal Tax Credit Carryforwards	$209.2	$163.7
State NOL Carryforwards (a)	$289.9	$294.4
State Tax Credit Carryforwards (b)	$25.6	$21.0


(a)	Pre-tax amounts.


(b)	Net of a $59.5 million valuation allowance as of December 31, 2017 ($42.7 million as of December 31, 2016).

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2017			2016			2015
Millions
Balance at January 1		$2.0			$2.4			$2.0
Additions for Tax Positions Related to the Current Year	0.1			0.1			0.5
Additions for Tax Positions Related to Prior Years	0.1			0.2			0.7
Reductions for Tax Positions Related to Prior Years	(0.1		)	(0.3		)	(0.7		)
Lapse of Statute	(0.4		)	(0.4		)	(0.1		)
Balance as of December 31		$1.7			$2.0			$2.4

Reclassifications Out of Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2017

Reclassifications Out of Accumulated Other Comprehensive Income (Loss) [Abstract]

Changes in Accumulated Other Comprehensive Loss [Table Text Block]

Changes in accumulated other comprehensive loss, net of tax, for the years ended December 31, 2017, 2016 and 2015, were as follows:



	Unrealized Gain (Loss) on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items (a)		Gain (Loss) on Cash Flow Hedge	Total
Millions
Balance as of December 31, 2014	$(0.3)		$(20.7)		$(0.1)	$(21.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.4	)	(4.3	)	0.1	(4.6	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1	)	1.3		—	1.2
Net Other Comprehensive Income (Loss)	(0.5	)	(3.0	)	0.1	(3.4	)
Balance as of December 31, 2015	(0.8	)	(23.7	)	—	(24.5	)
Other Comprehensive Income (Loss) Before Reclassifications	—		(4.1	)	—	(4.1	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.2	)	0.6		—	0.4
Net Other Comprehensive Income (Loss)	(0.2	)	(3.5	)	—	(3.7	)
Balance as of December 31, 2016	(1.0	)	(27.2	)	—	(28.2	)
Other Comprehensive Income (Loss) Before Reclassifications	1.1		3.9		—	5.0
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.2	)	0.8		—	0.6
Net Other Comprehensive Income (Loss)	0.9		4.7		—	5.6
Balance as of December 31, 2017	$(0.1)		$(22.5)		—	$(22.6)


(a)	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 15. Pension and Other Postretirement Benefit Plans.)

Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2017

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2018		$46.3		$9.2
2019		$46.2		$9.5
2020		$45.9		$9.6
2021		$45.8		$9.6
2022		$45.8		$9.6
Years 2023 – 2027		$228.0		$49.7

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



	Pension	Postretirement Health and Life
Millions
Net Loss	$12.0	$0.7
Prior Service Credit	—	(1.8	)
Total Pension and Postretirement Health and Life Cost (Credit)	$12.0	$(1.1)

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



Assumptions Used to Determine Benefit Obligation
As of December 31	2017	2016
Discount Rate
Pension	3.81 - 3.96%	4.53%
Postretirement Health and Life	3.86%	4.57%
Rate of Compensation Increase	3.70 - 4.10%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	5.00 - 6.73%	5.00 - 7.00%
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	2017	2016	2015
Discount Rate	4.53 - 4.57%	4.72 - 4.73%	4.30 - 4.33%
Expected Long-Term Return on Plan Assets
Pension	7.50%	8.00%	8.00%
Postretirement Health and Life	6.00 - 7.50%	6.40 - 8.00%	6.40 - 8.00%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%	3.70 - 4.30%

Plan Asset Actual and Target Allocations [Table Text Block]



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2017		2016		2017		2016
Equity Securities	53	%	49	%	64	%	60	%
Debt Securities	38	%	39	%	31	%	34	%
Private Equity	5	%	7	%	5	%	6	%
Real Estate	4	%	5	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Following are the current targeted allocations as of December 31, 2017:



Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	56	%	60	%
Debt Securities	35	%	37	%
Real Estate	9	%	3	%
	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Obligation and Funded Status [Table Text Block]



Pension Obligation and Funded Status
As of December 31	2017			2016
Millions
Accumulated Benefit Obligation		$745.4			$698.8
Change in Benefit Obligation
Obligation, Beginning of Year		$743.3			$709.8
Service Cost	10.2			8.1
Interest Cost	32.5			33.2
Actuarial Loss	44.8			12.4
Benefits Paid	(51.0		)	(44.5		)
Participant Contributions	13.4			24.3
Obligation, End of Year		$793.2			$743.3
Change in Plan Assets
Fair Value, Beginning of Year		$557.5			$521.3
Actual Return on Plan Assets	91.6			48.8
Employer Contribution (a)	30.1			31.9
Benefits Paid	(51.0		)	(44.5		)
Fair Value, End of Year		$628.2			$557.5
Funded Status, End of Year	$(165.0)			$(185.8)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.4)			$(1.4)
Non-Current Liabilities	$(163.6)			$(184.4)


(a)	Includes Participant Contributions noted above.

Amounts Recognized in Consolidated Balance Sheet [Table Text Block]



Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
As of December 31	2017	2016
Millions
Net Loss	$(236.2)	$(250.4)
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	71.2	64.6
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$(165.0)	$(185.8)

Components of Net Periodic Cost [Table Text Block]



Components of Net Periodic Pension Cost
Year Ended December 31	2017			2016			2015
Millions
Service Cost		$10.2			$8.1			$10.1
Interest Cost	32.5			33.2			29.9
Expected Return on Plan Assets	(42.4		)	(43.6		)	(40.7		)
Amortization of Loss	9.9			9.5			17.9
Amortization of Prior Service Cost	—			—			0.2
Net Pension Cost		$10.2			$7.2			$17.4

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	2017		2016
Millions
Net (Gain) Loss	$(4.3)			$7.2
Amortization of Loss	(9.9	)	(9.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(14.2)		$(2.3)

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	2017		2016
Millions
Projected Benefit Obligation		$793.2		$743.3
Accumulated Benefit Obligation		$745.4		$698.8
Fair Value of Plan Assets		$628.2		$557.5

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$94.6	—		—			$94.6
U.S. Mid-cap Growth (a)	—			$44.8	—		44.8
U.S. Small-cap (a)	—		45.0		—		45.0
International	46.7		42.3		—		89.0
Debt Securities:
Fixed Income	—		200.1		—		200.1
Cash and Cash Equivalents	17.8		—		—		17.8
Private Equity Funds	—		—			$40.6	40.6
Real Estate	—		—		25.6		25.6
Total Fair Value of Assets		$159.1		$332.2		$66.2		$557.5

(a)



	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
Debt Securities:
Fixed Income	—		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, 2015		$43.3			$28.9
Actual Return on Plan Assets	5.0			2.3
Purchases, Sales, and Settlements – Net	(7.7		)	(5.6		)
Balance as of December 31, 2016		$40.6			$25.6



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

Obligation and Funded Status [Table Text Block]



Postretirement Health and Life Obligation and Funded Status
As of December 31	2017			2016
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$173.4			$160.2
Service Cost	4.4			3.9
Interest Cost	7.7			7.4
Actuarial Loss	15.5			11.9
Benefits Paid	(12.2		)	(13.1		)
Participant Contributions	3.1			3.1
Plan Amendments	(1.8		)	—
Obligation, End of Year		$190.1			$173.4
Change in Plan Assets
Fair Value, Beginning of Year		$154.3			$153.4
Actual Return on Plan Assets	24.5			9.6
Employer Contribution	1.3			1.3
Participant Contributions	3.1			3.1
Benefits Paid	(12.2		)	(13.1		)
Fair Value, End of Year		$171.0			$154.3
Funded Status, End of Year	$(19.1)			$(19.1)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$3.0			$1.4
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(21.0)			$(19.4)

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	2017		2016
Millions
Net Loss (a)	$(21.1)		$(19.8)
Prior Service Credit	4.6		4.7
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a)	(2.6	)	(4.0	)
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet	$(19.1)		$(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	2017			2016			2015
Millions
Service Cost		$4.4			$3.9			$4.3
Interest Cost	7.7			7.4			7.2
Expected Return on Plan Assets	(10.5		)	(11.2		)	(10.9		)
Amortization of Loss	0.3			0.2			0.4
Amortization of Prior Service Credit	(2.0		)	(2.9		)	(3.0		)
Net Postretirement Health and Life Credit	$(0.1)			$(2.6)			$(2.0)

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



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2017			2016
Millions
Net Loss		$1.6			$13.5
Prior Service Credit Arising During the Period	(1.8		)	—
Amortization of Prior Service Credit	2.0			2.9
Amortization of Loss	(0.3		)	(0.2		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$1.5			$16.2

Unrecognized Postretirement Health and Life Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
As of December 31	2017		2016
Millions
Net Loss	$21.1		$19.8
Prior Service Credit	(4.6	)	(4.7	)
Total Unrecognized Postretirement Health and Life Cost	$16.5		$15.1

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



Sensitivity of a One Percent Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.9		($1.5	)
Effect on Postretirement Health and Life Obligation		$23.4		($19.3	)

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities: (a)
U.S. Large-cap		$27.9	—		—			$27.9
U.S. Mid-cap Growth	20.7		—		—		20.7
U.S. Small-cap	14.0		—		—		14.0
International	27.9		—		—		27.9
Debt Securities:
Mutual Funds	48.6		—		—		48.6
Fixed Income	—			$4.6	—		4.6
Cash and Cash Equivalents	1.1		—		—		1.1
Private Equity Funds	—		—			$9.5	9.5
Total Fair Value of Assets		$140.2		$4.6		$9.5		$154.3


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



	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
Debt Securities:
Mutual Funds	49.8		—		—		49.8
Fixed Income	—			$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).

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, 2015		$12.0
Actual Return on Plan Assets	1.4
Purchases, Sales, and Settlements – Net	(3.9		)
Balance as of December 31, 2016		$9.5



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, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employee Stock Ownership Plan [Table Text Block]



As of December 31	2017	2016	2015
Millions
ESOP Shares
Allocated	1.4	1.6	1.8
Unallocated	—	—	—
Total	1.4	1.6	1.8
Fair Value of Unallocated Shares	—	—	—

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	2017		2016		2015
Millions
Performance Shares		$2.1		$1.8		$1.8
Restricted Stock Units	1.0		0.8		0.8
Total Share-Based Compensation Expense		$3.1		$2.6		$2.6
Income Tax Benefit		$0.9		$1.1		$1.1

Non-Qualified Stock Options [Table Text Block]

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options.



	2017				2016				2015
	Number of Options		Weighted-Average Exercise Price		Number of Options		Weighted-Average Exercise Price		Number of Options		Weighted-Average Exercise Price
Outstanding as of January 1	4,357			$40.29	39,654			$44.39	66,279			$44.39
Exercised	(4,357	)		$40.29	(35,297	)		$44.89	(24,456	)		$44.52
Forfeited	—		—		—		—		(2,169	)		$42.93
Outstanding as of December 31	—		—		4,357			$40.29	39,654			$44.39
Exercisable as of December 31	—		—		4,357			$40.29	39,654			$44.39

Performance Shares [Table Text Block]

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



	2017				2016				2015
	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	127,580			$52.56	119,540			$52.72	119,635			$48.26
Granted (a)	50,729			$62.90	57,189			$52.43	43,583			$58.95
Unearned Grant Award	(40,801	)		$46.27	(42,126	)		$52.70	(36,670	)		$45.41
Forfeited	(9,610	)		$58.29	(7,023	)		$53.45	(7,008	)		$53.49
Non-vested as of December 31	127,898			$58.23	127,580			$52.56	119,540			$52.72

(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.



	2017				2016				2015
	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	54,728			$51.79	57,694			$49.86	53,888			$44.47
Granted (a)	21,241			$62.20	20,351			$50.25	26,702			$54.81
Awarded	(17,281	)		$49.72	(19,661	)		$44.33	(19,464	)		$41.44
Forfeited	(3,440	)		$56.00	(3,656	)		$52.87	(3,432	)		$51.52
Available as of December 31	55,248			$56.18	54,728			$51.79	57,694			$49.86

(a) Shares granted include accrued dividends.

Business Segments (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Business Segments [Table Text Block]



Year Ended December 31	2017			2016			2015
Millions
Operating Revenue
Regulated Operations		$1,063.8			$1,000.7			$991.2

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	80.5			80.5			262.1
U.S. Water Services	151.8			137.5			119.8

Corporate and Other	123.2			121.0			113.3
Total Operating Revenue		$1,419.3			$1,339.7			$1,486.4
Net Income (Loss) Attributable to ALLETE (b)(c)
Regulated Operations		$128.4			$135.5			$131.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	41.5			13.4			29.9
U.S. Water Services	10.7			1.5			0.9

Corporate and Other	(8.4		)	4.9			(21.3		)
Total Net Income Attributable to ALLETE		$172.2			$155.3			$141.1
Depreciation and Amortization
Regulated Operations		$132.6			$154.3			$135.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	23.4			22.3			18.7
U.S. Water Services	9.8			8.9			7.3

Corporate and Other	11.7			10.3			8.9
Total Depreciation and Amortization		$177.5			$195.8			$170.0
Operating Expenses – Other (d)
ALLETE Clean Energy	—				$3.3		—
Corporate and Other	$(0.7)			(13.6		)	$36.3
Total Operating Expenses – Other	$(0.7)			$(10.3)			$36.3
Interest Expense (c)
Regulated Operations	$57.0			$52.1			$53.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	4.2			5.8			3.3
U.S. Water Services	1.6			1.7			1.4

Corporate and Other	10.3			14.5			8.6

Eliminations	(5.3		)	(3.8		)	(2.3		)
Total Interest Expense	$67.8			$70.3			$64.9
Equity Earnings in ATC
Regulated Operations	$22.5			$18.5			$16.3


(a)	Includes the construction and sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities for $197.7 million in 2015.

(b)


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


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



Year Ended December 31	2017			2016		2015
Millions
Income Tax Expense (Benefit) (a)
Regulated Operations (b)		$27.2			$5.9		$24.4

Energy Infrastructure and Related Services
ALLETE Clean Energy	(14.2		)	8.1		21.0
U.S. Water Services	(7.8		)	1.4		0.9

Corporate and Other (b)	9.5			4.4		(21.0		)
Total Income Tax Expense		$14.7			$19.8		$25.3

(a)

(b)



As of December 31	2017		2016
Millions
Assets
Regulated Operations (a)	$3,886.6		$3,823.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	600.5		566.0
U.S. Water Services	292.4		264.1

Corporate and Other	300.5		222.9
Total Assets (a)		$5,080.0		$4,876.9
Capital Expenditures
Regulated Operations	$177.1		$121.8

Energy Infrastructure and Related Services
ALLETE Clean Energy	56.1		106.9
U.S. Water Services	4.4		3.7

Corporate and Other	28.9		15.4
Total Capital Expenditures		$266.5		$247.8


(a)	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited) [Table Text Block]



Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2017
Operating Revenue		$365.6		$353.3		$362.5		$337.9
Operating Income		$72.6		$55.0		$69.0		$33.2
Net Income Attributable to ALLETE		$49.0		$36.9		$44.9		$41.4
Earnings Per Share of Common Stock
Basic		$0.97		$0.73		$0.88		$0.81
Diluted		$0.97		$0.72		$0.88		$0.81
2016
Operating Revenue		$333.8		$314.8		$349.6		$341.5
Operating Income		$66.8		$42.2		$53.4		$61.1
Net Income Attributable to ALLETE		$45.9		$24.8		$40.3		$44.3
Earnings Per Share of Common Stock
Basic		$0.93		$0.50		$0.82		$0.89
Diluted		$0.93		$0.50		$0.81		$0.89
2015
Operating Revenue		$320.0		$323.3		$462.5		$380.6
Operating Income		$56.4		$39.5		$85.2		$29.6
Net Income Attributable to ALLETE		$39.9		$22.5		$60.4		$18.3
Earnings Per Share of Common Stock
Basic		$0.85		$0.46		$1.24		$0.37
Diluted		$0.85		$0.46		$1.23		$0.37

Operations and Significant Accounting Policies - Business Segments (Details)	12 Months Ended
	Dec. 31, 2017 a Customers MW
Business Segments [Line Items]
Number of Reportable Segments	3
Square Butte [Member] \| Square Butte PPA [Member]
Business Segments [Line Items]
Minnesota Power Output Entitlement (Percent)	50.00%
Minnesota Power Output Entitlement (MW) \| MW	227.5
Regulated Operations [Member]
Business Segments [Line Items]
Alternative Revenue Program, Required Collection Period (Months)	24 months
Regulated Operations [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Electric [Member]
Business Segments [Line Items]
Number of Customers	145,000
Regulated Operations [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Electric [Member]
Business Segments [Line Items]
Number of Customers	16
Regulated Operations [Member] \| SWL&P [Member] \| Retail Customers [Member] \| Electric [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	535
Corporate and Other [Member]
Business Segments [Line Items]
Land in Minnesota (Acres) \| a	5,000
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 - Supplemental Statement of Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$ 64.5	$ 68.2	$ 59.0
Cash Paid During the Period for Income Taxes	0.4	0.5	0.4
Remeasurement of Deferred Income Taxes Resulting from the TCJA [Abstract]
Increase to Regulatory Assets	80.9	0.0	0.0
Decrease in Investment in ATC	(27.9)	0.0	0.0
Decrease to Deferred Income Taxes	(353.6)	0.0	0.0
Increase to Regulatory Liabilities	393.6	0.0	0.0
Noncash Investing and Financing Activities [Abstract]
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	67.2	22.0	40.6
Capitalized Asset Retirement Costs	(15.6)	3.7	12.4
Camp Ripley Solar Financing	0.0	15.0	0.0
AFUDC–Equity	1.2	2.1	3.3
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	13.5	0.0	0.0
Contingent Consideration	0.0	0.0	35.7
Noncash Consideration for Land Inventory [Line Items]
Consideration for Land Inventory		21.0
ALLETE Common Stock Received for Land Inventory [Member]
Noncash Consideration for Land Inventory [Line Items]
Consideration for Land Inventory	0.0	8.0	0.0
Long-Term Finance Receivable for Land Inventory [Member]
Noncash Consideration for Land Inventory [Line Items]
Consideration for Land Inventory	$ 0.0	$ 12.0	$ 0.0

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, 2017 USD ($) Customers	Dec. 31, 2016 USD ($) Customers	Dec. 31, 2015 Customers
Concentration Risk [Line Items]
Number of Large Power Customers \| Customers	9	9	9
Receivables from Large Power Customers \| $	$ 13.8	$ 9.5
Largest Customer [Member] \| Consolidated Operating Revenue [Member]
Concentration Risk [Line Items]
Percent of Consolidated Operating Revenue	10.00%	8.00%	8.00%

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Accounts Receivable [Abstract]

Billed

$ 112.6

$ 106.5

Unbilled

24.6

19.1

Less: Allowance for Doubtful Accounts

2.1

3.1

Total Accounts Receivable

135.1

122.5

Inventories – Net [Abstract]

Fuel

^[1]

34.8

43.9

Materials and Supplies

46.5

48.7

Raw Materials

2.8

2.9

Work in Progress

4.2

1.0

Finished Goods

8.3

8.6

Reserve for Obsolescence

(0.7)

(0.9)

Total Inventories

95.9

104.2

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

^[2]

0.0

18.6

Restricted Cash

^[3]

2.6

2.2

Total Prepayments and Other Current Assets

35.0

19.5

37.6

40.3

Impairment of Long-Lived Assets [Abstract]

0.0

$ 36.3

Indefinite-Lived Intangible Assets [Abstract]

0.0

3.3

^[4]

0.0

Impairment of Intangible Assets

0.0

Other Non-Current Assets [Abstract]

Contract Payment

^[5]

27.5

29.6

Financing Receivable

^[6]

11.0

11.5

Restricted Cash

^[7]

8.6

Total Other Non-Current Assets

60.6

56.8

107.7

106.5

Real Estate Sale Consideration [Abstract]

Total Consideration for Land Inventory

$ 21.0

Down Payment of ALLETE Common Stock (Shares)

0.1

Down Payment of ALLETE Common Stock

$ 8.0

Finance Receivable Term (Years)

5 years

Other Current Liabilities [Abstract]

PSAs

24.5

$ 24.6

Total Other Current Liabilities

58.7

49.1

83.2

73.7

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

122.7

136.6

PSAs

89.5

113.8

Contingent Consideration

^[8]

5.4

25.0

Total Other Non-Current Liabilities

49.5

47.3

267.1

322.7

Amortization of Power Sales Agreements

396.9

339.9

336.0

23.6

22.3

23.2

Operating Expenses – Other [Abstract]

0.0

36.3

Change in Fair Value of Contingent Consideration

0.0

3.3

^[4]

0.0

(0.7)

(13.6)

0.0

Total Operating Expenses – Other

$ (0.7)

$ (10.3)

$ 36.3

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

35.00%

Deferred Income Tax Expense (Benefit)

$ 14.4

$ 19.4

$ 25.1

Decrease to Deferred Income Taxes

(353.6)

0.0

Decrease in Investment in ATC

(27.9)

0.0

Increase to Regulatory Assets

80.9

0.0

Increase to Regulatory Liabilities

393.6

0.0

Income Tax Expense [Member]

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

Deferred Income Tax Expense (Benefit)

$ (13.0)

Subsequent Event [Member]

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

Statutory Federal Income Tax Rate

21.00%

Regulated Operations [Member]

Alternative Revenue Program, Required Collection Period (Months)

24 months

3.3

^[4]

0.0

Amortization of Power Sales Agreements

$ 23.6

22.3

23.2

Operating Expenses – Other [Abstract]

3.3

^[4]

0.0

Revenue Growth Rate Related to Impact of Acquisition

$ 0.0

0.0

^[4]

0.0

Discount Rate

10.75%

13.00%

Terminal Growth Rate

4.00%

Operating Expenses – Other [Abstract]

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

$ 0.0

^[4]

$ 0.0

Annual Revenue Growth Rate

7.00%

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

Annual Revenue Growth Rate

9.00%

Corporate and Other [Member]

Minimum Cash Collections Requirement for Real Estate Sales (Percent)

20.00%

2016 Minnesota General Rate Case [Member] | MPUC [Member] | Minnesota Power [Member]

2016 Minnesota General Rate Case [Member] | Regulated Operations [Member] | MPUC [Member] | Minnesota Power [Member]

$ 19.5

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

$ 19.5

Definite-Lived Intangible Assets [Line Items]

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

1 year

Definite-Lived Intangible Assets [Line Items]

Customer Relationships [Member] | Maximum [Member]

11 years

Definite-Lived Intangible Assets [Line Items]

20 years

[1]	Fuel consists primarily of coal inventory at Minnesota Power.
[2]	At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017.
[3]	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and collateral deposits required for U.S. Water Services’ standby letters of credit.
[4]	The facts and circumstances that led to an impairment of ALLETE Clean Energy’s goodwill primarily relate to lower estimated energy prices in periods not under PSAs. Impairment Charge is included in Operating Expenses – Other on the Consolidated Statement of Income. (See Note 1. Operations and Significant Accounting Policies.) ALLETE Clean Energy’s goodwill was primarily related to the acquisition of Storm Lake II in 2014.
[5]	Contract Payment includes a payment made to Cliffs as part of a long-term PSA between Minnesota Power and Silver Bay Power. The contract payment is being amortized over the term of the PSA. (See Note 11. Commitments, Guarantees and Contingencies.)
[6]	n 2016, ALLETE Properties sold its Ormond Crossings project and Lake Swamp wetland mitigation bank for consideration of approximately $21 million. The consideration included a down payment in the form of 0.1 million shares of ALLETE common stock with a value of $8.0 million. The remaining purchase price will be paid under the terms of a finance receivable due over a five-year period which bears interest at market rates and is collateralized by the property sold.
[7]	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.
[8]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 6. Acquisitions and Note 9. Fair Value.)

Operations and Significant Accounting Policies - New Accounting Pronouncements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
New Accounting Standards [Line Items]
Expected Minimum Lease Payment Due in Future Years	$ 79.9
Income Tax Expense [Member]
New Accounting Standards [Line Items]
Effect of the Adoption	$ 1.0

Operations and Significant Accounting Policies - Reclassification of Prior Income Statement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Operating Revenue – Utility [Member]
Schedule of Prior Period Reclassification Adjustments [Line Items]
Prior Period Reclassification Adjustment	$ 1,007.7	$ 991.2
Operating Revenue – Non-utility [Member]
Schedule of Prior Period Reclassification Adjustments [Line Items]
Prior Period Reclassification Adjustment	339.0	495.2
Fuel, Purchased Power and Gas – Utility [Member]
Schedule of Prior Period Reclassification Adjustments [Line Items]
Prior Period Reclassification Adjustment	$ 7.0	$ 7.9

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Asset Retirement Obligation [Roll Forward]

$ 3,822.4

$ 3,741.2

Beginning Obligation

136.6

131.4

Accretion

7.6

8.0

Liabilities Settled

(5.9)

(6.5)

Revisions in Estimated Cash Flows

(15.6)

3.7

$ 12.4

Ending Obligation

122.7

136.6

$ 131.4

Regulated Operations [Member]

Construction Work in Progress

4,523.7

4,437.0

121.6

84.2

(1,520.5)

(1,426.1)

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

$ 3,124.8

3,095.1

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

5 years

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

50 years

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

44 years

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

67 years

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

18 years

65 years

Construction Work in Progress

$ 482.5

472.3

144.9

101.0

(60.8)

(41.0)

ALLETE Clean Energy [Member] | Minimum [Member]

$ 566.6

532.3

ALLETE Clean Energy [Member] | Maximum [Member]

5 years

35 years

$ 24.8

19.5

(10.4)

(6.9)

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

$ 14.4

12.6

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

3 years

Corporate and Other [Member]

39 years

Construction Work in Progress

^[1]

$ 204.7

179.8

^[1]

5.0

2.8

^[1]

(93.1)

(81.4)

Corporate and Other [Member] | Minimum [Member]

$ 116.6

$ 101.2

Corporate and Other [Member] | Maximum [Member]

3 years

Minnesota Power [Member] | Resource Package [Member] | Natural Gas PPA [Member]

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, 2017 USD ($) MW	Dec. 31, 2016 USD ($)
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 769.2	$ 769.3
Accumulated Depreciation	231.2	217.1
Construction Work in Progress	$ 8.2	$ 8.1
Transmission [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	3	3
Plant in Service	$ 101.0	$ 101.2
Accumulated Depreciation	8.4	5.9
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
WPPI Energy Ownership %	20.00%
Plant in Service	$ 668.2	$ 668.1
Accumulated Depreciation	222.8	211.2
Construction Work in Progress	$ 8.2	$ 8.1

Regulatory Matters - Electric Rates (Details) $ in Millions			1 Months Ended		5 Months Ended	7 Months Ended	12 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Jan. 18, 2018 USD ($)	Apr. 13, 2017 USD ($)	Dec. 31, 2016 USD ($)	Nov. 30, 2016 USD ($)	Dec. 31, 2017 USD ($) Customers Years MW	Aug. 13, 2017	Dec. 31, 2017 USD ($) Customers Years MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Regulatory Matters [Line Items]
Charge to Fuel, Purchased Power and Gas - Utility							$ 396.9	$ 339.9	$ 336.0
Reduction in Operating Revenue due to Regulatory Outcome							1,063.8	1,000.7	991.2
Energy-Intensive Trade-Exposed Customer Rates [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Discount Provided to EITE Customers							8.6
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		25.0
PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Return on Equity						10.90%
Annual Additional Revenue Generated from Requested Final Rate Increase							2.5
Approved Return on Common Equity					10.50%
Approved Equity Ratio					55.00%
Approved Rate Increase (Decrease), Percentage					2.90%
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							$ 96.9	97.1	$ 89.6
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)							9.00%
Requested Return on Equity							10.25%
Requested Equity Ratio							53.81%
Annual Additional Revenue Generated from Requested Final Rate Increase							$ 55.0
Annual Additional Revenue Generated from Requested Interim Rate Increase		$ 32.2	$ 34.7	$ 49.0			34.7
Requested Rate Increase, Amended, Amount				$ 49.0
Reserve for Interim Rate Refund					$ 32.0		32.0
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Subsequent Event [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity	9.25%
Approved Equity Ratio	53.81%
Approved Rate Increase - Amount	$ 13.0
Electric Rates [Member] \| MPUC [Member] \| Energy-Intensive Trade-Exposed Customer Rates [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Discount Provided to EITE Customers							8.6
Estimated Discount to be Provided During the Next Twelve Months					$ 15.0		15.0
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
Reduction in Operating Revenue due to Regulatory Outcome								$ 15.0
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers					16		16
Notice Required to Terminate (Years) \| Years					3		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		29
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		14
Electric Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase (Decrease), Percentage					3.80%
Natural Gas Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase (Decrease), Percentage					4.80%
Water Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase (Decrease), Percentage					9.80%

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - MW

Jul. 28, 2017

Dec. 31, 2017

Dec. 31, 2015

Natural Gas-Fired [Member] | Minnesota Power [Member] | Resource Package [Member] | Natural Gas PPA [Member]

250

Output Purchased (Percent)

50.00%

Natural Gas-Fired [Member] | Minimum [Member] | Minnesota Power [Member] | Integrated Resource Plan [Member]

525

Generating Capacity Owned (MW)

200

Natural Gas-Fired [Member] | Maximum [Member] | Minnesota Power [Member] | Integrated Resource Plan [Member]

550

Generating Capacity Owned (MW)

300

Wind Turbine Generators [Member] | Resource Package [Member] | Tenaska [Member] | Tenaska PPA [Member]

Wind Turbine Generators [Member] | Minnesota Power [Member] | Resource Package [Member] | Tenaska [Member] | Tenaska PPA [Member]

^[1]

250

Solar Energy Generation [Member] | Minnesota Power [Member] | Resource Package [Member] | Solar Energy PPA [Member]

250

[1]	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota and is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired facility. (See Note 4. Regulatory Matters.)

Regulatory Matters - Great Northern Transmission Line (Details) - Great Northern Transmission Line [Member] $ in Millions	Dec. 31, 2017 USD ($) kV Miles
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Total Project Costs to Date - Incurred	$ 152.4
Minimum [Member]
Regulatory Matters [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	560.0
Maximum [Member]
Regulatory Matters [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	710.0
Minnesota Power [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	300.0
Minnesota Power [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	350.0
Manitoba Hydro [Member]
Regulatory Matters [Line Items]
Total Project Costs to Date - Recovered	$ 67.6
MPUC [Member] \| Certificate of Need and Route Permit [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, 2017	Dec. 31, 2016	Dec. 31, 2015
Minimum [Member]
Regulatory Matters [Line Items]
CIP Spending Minimum - Percentage	1.50%
CIP Triennial Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Annual Energy-Savings Goal - Percentage	1.50%
CIP Investment Goal	$ 10.3	$ 7.3	$ 7.1
CIP Actual Spending	8.1	7.4	6.6
CIP Investment Goal in 2018	10.3
CIP Investment Goal in 2019	10.5
CIP Consolidated Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Financial Incentive	$ 5.5	$ 7.5	$ 6.2

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Dec. 31, 2017
Return on Equity Complaint 1 [Member]
Loss Contingencies [Line Items]
Requested Return on Equity Filed with the FERC by Third Party	9.15%
FERC Authorized Return on Equity	10.32%
FERC Authorized Return on Equity Including Incentive Adder	10.82%
Return on Equity Complaint 2 [Member]
Loss Contingencies [Line Items]
Requested Return on Equity Filed with the FERC by Third Party	8.67%
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) - MW	Dec. 31, 2017	Dec. 31, 2016
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Qualifying Capacity for Small Scale Solar Mandate (MW)	40
MPUC [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Overall Mandate Percentage	1.50%
MPUC [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Overall Mandate Percentage	1.50%
Solar Energy Standard Mandate - Small Scale Solar Mandate Percentage	10.00%
MPUC [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Qualifying Capacity for Small Scale Solar Mandate (MW)		0.02
MPUC [Member] \| Minnesota Solar Energy Standard - Camp Ripley Project [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	10
MPUC [Member] \| Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Counterparty Owned (MW)	1
MPUC [Member] \| 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

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

$ 384.7

$ 330.1

Total Regulatory Assets

384.7

348.7

532.0

125.8

Minnesota Power [Member] | Energy-Intensive Trade-Exposed Customer Rates [Member]

396.9

339.9

$ 336.0

Discount Provided to EITE Customers

8.6

MPUC [Member] | Minnesota Power [Member] | 2016 Minnesota General Rate Case [Member]

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

19.5

Discount Provided to EITE Customers

8.6

Income Taxes [Member]

Wholesale and Retail Contra AFUDC [Member]

^[1]

411.2

19.1

Revenue Subject to Refund [Member]

^[2]

57.9

56.8

Plant Removal Obligations [Member]

^[3]

23.7

0.0

North Dakota Investment Tax Credits [Member]

20.3

19.1

Cost Recovery Riders [Member]

^[4]

14.1

28.2

^[5]

2.2

0.0

Other [Member]

Deferred Fuel Adjustment Clause [Member]

2.6

Current Regulatory Assets

^[6]

0.0

18.6

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

^[7]

220.3

226.1

Income Taxes [Member]

Asset Retirement Obligation [Member]

^[1],[8]

112.8

33.8

Manufactured Gas Plant [Member]

^[9]

29.6

26.0

PPACA Income Tax Deferral [Member]

^[10]

8.1

1.0

Conservation Improvement Program [Member]

5.0

Cost Recovery Riders [Member]

^[11]

3.3

4.0

Alternative Revenue Program, Required Collection Period (Years)

^[5]

0.0

$ 30.5

2 years

Other [Member]

$ 5.6

$ 3.7

[1]	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The increase in 2017 is primarily due to the remeasurement of deferred income tax assets and liabilities for our Regulated Operations resulting from the TCJA. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the U.S. Internal Revenue Code over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. (See Note 1. Operations and Significant Accounting Policies, and Tax Cuts and Jobs Act of 2017.) The balances not related to remeasurement will decrease over the remaining life of the related temporary differences and flow through current income taxes.
[2]	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.
[3]	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $8.6 million of EITE discounts that will be offset against interim rate refunds. (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)
[4]	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 fillings as the tax credits are utilized.
[5]	The cost recovery rider regulatory assets and liabilities are revenues not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL, and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets and liabilities as of December 31, 2017, will be recovered or returned within the next two years.
[6]	ued)Regulatory Assets and Liabilities As of December 3120172016Millions Current Regulatory Assets (a) Deferred Fuel Adjustment Clause—$18.6Non-Current Regulatory Assets Defined Benefit Pension and Other Postretirement Benefit Plans (b)$220.3226.1Income Taxes (c)(d)112.833.8Asset Retirement Obligations (e)29.626.0Manufactured Gas Plant (f)8.11.0PPACA Income Tax Deferral5.05.0Conservation Improvement Program (g)3.34.0Cost Recovery Riders (h)—30.5Other5.63.7Total Non-Current Regulatory Assets384.7330.1Total Regulatory Assets$384.7$348.7Non-Current Regulatory Liabilities Income Taxes (d)$411.2$19.1Wholesale and Retail Contra AFUDC (i)57.956.8Provision for Interim Rate Refund (j)23.7—Plant Removal Obligations20.319.1North Dakota Investment Tax Credits (k)14.128.2Cost Recovery Riders (h)2.2—Other2.62.6Total Non-Current Regulatory Liabilities$532.0$125.8(a)Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. (See 2016 Minnesota General Rate Case.)
[7]	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 15. Pension and Other Postretirement Benefit Plans.)
[8]	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.
[9]	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
[10]	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.
[11]	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.

Investment in ATC (Details) - USD ($) $ in Millions		12 Months Ended
Investment in ATC (Details) - USD ($) $ in Millions	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 27, 2016
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance		$ 135.6
Cash Investments		7.8	$ 5.4	$ 1.6
Equity Earnings in ATC		22.5	18.5	16.3
Remeasurement of Deferred Income Taxes		(27.9)	0.0	0.0
Equity Investment Ending Balance		118.7	135.6
Income Statement Data [Abstract]
ALLETE's Equity in Net Income		$ 22.5	18.5	16.3
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]
Investment in ATC [Line Items]
Ownership Percentage		8.00%
Expected Additional Investment in 2018		$ 6.0
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance		135.6	124.5
Cash Investments		7.8	5.4
Equity Earnings in ATC		22.5	18.5	16.3
Distributed ATC Earnings		(19.3)	(12.8)
Equity Investment Ending Balance		118.7	135.6	124.5
Balance Sheet Data [Abstract]
Current Assets		87.7	75.8
Non-Current Assets		4,598.9	4,312.9
Total Assets		4,686.6	4,388.7
Current Liabilities		767.2	495.1
Long-Term Debt		1,790.6	1,865.3
Other Non-Current Liabilities		240.3	271.5
Members' Equity		1,888.5	1,756.8
Total Liabilities and Members' Equity		4,686.6	4,388.7
Income Statement Data [Abstract]
Revenue		721.6	650.8	615.8
Operating Expense		344.9	322.5	319.3
Other Expense		104.1	95.5	96.1
Net Income		272.6	232.8	200.4
ALLETE's Equity in Net Income		$ 22.5	18.5	$ 16.3
Authorized Return on Equity		10.32%			12.20%
Authorized Return on Equity, Including Incentive Adder		10.82%
ATC [Member] \| Subsequent Event [Member]
ALLETE's Investment in ATC [Roll Forward]
Cash Investments	$ 1.6
Investment in ATC [Member]
ALLETE's Investment in ATC [Roll Forward]
Remeasurement of Deferred Income Taxes		$ (27.9)	$ 0.0

Acquisitions (Details)	12 Months Ended
Acquisitions (Details)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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 acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.	The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.
Pro Forma Impact of Business Acquisitions	not significant	not significant

Acquisitions - Tonka Water (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Sep. 01, 2017

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

$ 0.2

$ 148.3

$ 131.2

$ 130.6

Tonka Water [Member]

100.00%

Tonka Water

$ 19.2

19.0

$ 0.2

Accounts Receivable

5.1

Other Current Assets

5.1

Trade Names

^[2]

0.9

^[2],[3]

16.9

0.2

28.2

9.0

9.0

19.2

$ 4.1

[1]	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition.
[2]	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)
[3]	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.

Acquisitions - Acquisition of Non-Controlling Interest (Details) - USD ($) $ in Millions		12 Months Ended
	Apr. 15, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition of Non-Controlling Interest [Line Items]
Payments to Acquire Additional Interest in Subsidiaries		$ 0.0	$ 8.0	$ 0.0
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) - USD ($)
$ in Millions

1 Months Ended

6 Months Ended

12 Months Ended

Oct. 11, 2016

Oct. 31, 2016

Jun. 30, 2017

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

$ 0.2

Water & Energy Systems Technology [Member]

$ 148.3

$ 131.2

$ 130.6

100.00%

Water & Energy Systems Technology of Nevada, Inc.

$ 6.7

5.9

Payments Due in April 2018

$ 0.2

$ 0.6

Cash and Cash Equivalents

$ 0.1

Other Current Assets

1.0

Intangible Assets

^[2]

2.8

^[2],[3]

4.2

0.1

8.2

0.3

1.2

1.5

6.7

$ 0.0

[1]	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition.
[2]	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)
[3]	For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisitions - U.S. Water Services (Details) - USD ($)
$ in Millions

1 Months Ended

11 Months Ended

12 Months Ended

Feb. 28, 2015

Dec. 31, 2015

Dec. 31, 2017

Dec. 31, 2016

$ 130.6

$ 148.3

$ 131.2

^[1]

$ 2.6

$ 2.2

U.S. Water Services

$ 202.3

Percent of Results of Operations Reflected in Income Statement

166.6

Contingent Consideration

$ 35.7

100.00%

100.00%

Cash and Cash Equivalents

$ 0.9

Accounts Receivable

16.8

Inventories

^[2]

13.4

Other Current Assets

^[3]

5.3

10.6

Intangible Assets

^[4]

83.0

^[5]

122.9

0.2

253.1

19.2

31.6

50.8

Fair Value Adjustments for Work in Progress and Finished Goods Inventories

202.3

2.7

Fair Value of Sales Backlog

1.6

2.1

Acquisition-Related Costs

$ 2.9

$ 3.0

[1]	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and collateral deposits required for U.S. Water Services’ standby letters of credit.
[2]	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of Sales within one year from the acquisition date.
[3]	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog was recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for standby letters of credit.
[4]	Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 7. Goodwill and Intangible Assets.)
[5]	For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill.

Acquisitions - Chanarambie/Viking (Details)
$ in Millions

1 Months Ended

12 Months Ended

Apr. 30, 2015

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Power Sales Agreements - Non-Current Liability

$ 89.5

$ 113.8

Power Sales Agreements - Current Liability

$ 130.6

148.3

131.2

$ 24.5

$ 24.6

Chanarambie/Viking [Member]

100.00%

Chanarambie/Viking

$ 48.0

97.5

Current Assets

$ 4.8

103.0

^[1]

1.0

108.8

Power Sales Agreements - Non-Current Liability

^[2]

6.7

49.0

5.1

60.8

48.0

0.3

Power Sales Agreements - Current Liability

0.0

$ 5.9

Acquisition-Related Costs

$ 0.2

Chanarambie/Viking [Member] | Chanarambie/Viking PPA (expires 2018) [Member]

Chanarambie/Viking [Member] | Chanarambie/Viking PPA (expires 2023) [Member]

85.5

[1]	Included in Other Non-Current Assets was $0.3 million of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[2]	Current Liabilities included $5.9 million related to the current portion of PSAs.

Acquisitions - Armenia Mountain (Details)
$ in Millions

1 Months Ended

12 Months Ended

Jul. 31, 2015

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Restricted Cash - Non-Current

^[1]

$ 2.6

$ 2.2

^[2]

$ 8.6

Armenia Mountain [Member]

100.00%

Armenia Mountain

$ 111.1

100.5

Current Assets

^[3]

$ 9.0

156.2

^[4]

14.4

179.6

Long-Term Debt Due Within One Year

2.9

5.9

Long-Term Debt

55.0

Other Non-Current Liabilities

4.7

68.5

Power Sales Agreements - Current Asset

111.1

1.0

Power Sales Agreements - Non-Current Asset

6.0

8.2

Restricted Cash - Non-Current

6.1

Acquisition-Related Costs

$ 0.0

$ 1.6

[1]	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and collateral deposits required for U.S. Water Services’ standby letters of credit.
[2]	Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.
[3]	Included in Current Assets was $1.0 million related to the current portion of PSAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.
[4]	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PSAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisitions - A and W Technologies (Details) - USD ($)
$ in Millions

1 Months Ended

Nov. 01, 2015

Nov. 30, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

A and W Technologies [Member]

$ 148.3

$ 131.2

$ 130.6

100.00%

A and W Technologies, Inc.

$ 9.3

Payment Due in April 2017

8.3

1.0

Current Assets

1.0

0.1

Intangible Assets

^[1]

3.9

^[2]

4.4

9.4

0.1

0.1

9.3

$ 4.4

[1]	Intangible Assets include customer relationships and non-compete agreements. (See Note 7. Goodwill and Intangible Assets.)
[2]	For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill.

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Goodwill [Roll Forward]

$ 131.2

$ 130.6

Acquired Goodwill

^[1]

16.9

3.9

Impairment Charge

0.0

(3.3)

^[2]

$ 0.0

Other Adjustments

^[3]

0.2

148.3

131.2

130.6

Goodwill [Roll Forward]

0.0

3.3

Acquired Goodwill

^[1]

0.0

Impairment Charge

(3.3)

^[2]

0.0

Other Adjustments

^[3]

0.0

0.0

3.3

Goodwill [Roll Forward]

131.2

127.3

Acquired Goodwill

^[1]

16.9

3.9

Impairment Charge

0.0

^[2]

0.0

Other Adjustments

^[3]

0.2

Definite-Lived Intangible Assets [Roll Forward]

$ 148.3

$ 131.2

$ 127.3

[1]	See Note 6. Acquisitions.
[2]	The facts and circumstances that led to an impairment of ALLETE Clean Energy’s goodwill primarily relate to lower estimated energy prices in periods not under PSAs. Impairment Charge is included in Operating Expenses – Other on the Consolidated Statement of Income. (See Note 1. Operations and Significant Accounting Policies.) ALLETE Clean Energy’s goodwill was primarily related to the acquisition of Storm Lake II in 2014.
[3]	Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition.

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 65.6

^[1]

0.9

Amortization

(5.5)

$ (5.2)

$ (4.0)

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

61.0

65.6

5.3

5.0

4.7

4.6

4.3

37.1

Intangible Assets [Abstract]

Total Intangible Assets

77.6

82.2

Total Intangible Assets, Additions

^[1]

0.9

Total Intangible Assets, Amortization

(5.5)

(5.2)

$ (4.0)

Accumulated Amortization

$ 14.8

9.3

Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Trademarks and Trade Names [Member]

7 years

Indefinite-Lived Intangible Assets [Roll Forward]

$ 16.6

^[1]

0.0

Customer Relationships [Member]

16.6

Definite-Lived Intangible Assets [Roll Forward]

59.3

^[1]

0.0

Amortization

(4.6)

Total Intangible Assets, Amortization

54.7

59.3

Intangible Assets [Abstract]

$ (4.6)

Customer Relationships [Member] | Maximum [Member]

Definite-Lived Intangible Assets [Roll Forward]

Developed Technology and Other [Member]

20 years

Definite-Lived Intangible Assets [Roll Forward]

^[2]

$ 6.3

^[1],[2]

0.9

Amortization

^[2]

(0.9)

Total Intangible Assets, Amortization

^[2]

6.3

$ 6.3

Intangible Assets [Abstract]

^[2]

$ (0.9)

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

Definite-Lived Intangible Assets [Roll Forward]

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

1 year

Definite-Lived Intangible Assets [Roll Forward]

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

11 years

Definite-Lived Intangible Assets [Roll Forward]

19 years

[1]	Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 6. Acquisitions.)
[2]	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Available-for-sale Securities

ALLETE Properties

$ 26.4

$ 31.7

^[1]

19.1

18.8

3.8

1.3

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

3.8

Total Other Investments

53.1

55.6

One Year or Less

0.7

One Year to Less Than Three Years

3.2

Three Years to Less Than Five Years

3.6

Five or More Years

1.4

Impairment of Land Inventory

$ 0.0

$ 36.3

[1]

As of December 31, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $3.2 million, in three years to less than five years was $3.6 million, and in five or more years was $1.4 million.

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

$ 3.8

$ 1.3

Recurring Fair Value Measures [Member]

^[1]

5.4

25.0

Available-for-sale – Corporate and Governmental Debt Securities

10.2

^[2]

7.1

^[3]

8.9

^[2]

11.7

^[3]

3.8

^[2]

1.3

^[3]

22.9

20.1

18.2

^[4]

16.0

^[5]

5.4

^[4]

25.0

^[5]

23.6

41.0

(0.7)

(20.9)

Fair Value Hierarchy Transfers, All Levels

0.0

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

Available-for-sale – Corporate and Governmental Debt Securities

10.2

^[2]

7.1

^[3]

0.0

^[2]

0.0

^[3]

3.8

^[2]

1.3

^[3]

14.0

8.4

0.0

^[4]

0.0

^[5]

0.0

^[4]

0.0

^[5]

0.0

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

14.0

8.4

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[2]

0.0

^[3]

8.9

^[2]

11.7

^[3]

0.0

^[2]

0.0

^[3]

8.9

11.7

18.2

^[4]

16.0

^[5]

0.0

^[4]

0.0

^[5]

18.2

16.0

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

(9.3)

(4.3)

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[2]

0.0

^[3]

0.0

^[2]

0.0

^[3]

0.0

^[2]

0.0

^[3]

0.0

0.0

^[4]

0.0

^[5]

5.4

^[4]

25.0

^[5]

5.4

25.0

(5.4)

(25.0)

25.0

36.6

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

5.4

25.0

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

Activity in Level 3

^[6]

(0.8)

(2.8)

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

Activity in Level 3

19.7

^[7]

0.8

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

Activity in Level 3

$ 0.7

^[7]

$ 13.6

^[8]

[1]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 6. Acquisitions and Note 9. Fair Value.)
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Investments on the Consolidated Balance Sheet.
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[5]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[6]	Included in Interest Expense on the Consolidated Statement of Income.
[7]	Payments and changes in cash flow projections 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 the first half of 2017.
[8]	During the fourth quarter of 2016, management assessed earnings estimates used in calculating the fair value of the U.S. Water Services contingent consideration liability and determined an adjustment was necessary to the liability’s carrying amount based on its assessment. As a result, we recorded a reduction of $13.6 million to the liability’s carrying amount which resulted in an after-tax gain of the same amount presented within Operating Expenses – Other in the Consolidated Statement of Income.

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,513.3	$ 1,569.1
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,627.6	$ 1,653.8

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Equity Method Investment, Carrying Amount

$ 118.7

$ 135.6

148.3

131.2

$ 130.6

Intangible Assets, Carrying Amount

0.0

3.3

^[1]

0.0

77.6

82.2

Intangible Assets, Indicators of Impairment

0.0

0.0

36.3

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

148.3

131.2

127.3

0.0

^[1]

0.0

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

$ 0.0

0.0

3.3

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

3.3

^[1]

0.0

ATC [Member]

Ownership Percentage

8.00%

Equity Method Investment, Carrying Amount

$ 118.7

135.6

124.5

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

77.6

82.2

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]

148.3

131.2

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

0.0

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

Property, Plant and Equipment, Indicators of Impairment

$ 36.3

$ 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]

Ownership Percentage

8.00%

Equity Method Investment, Carrying Amount

$ 118.7

135.6

Equity Method Investment, Indicators of Impairment

$ 0.0

[1]

Short-Term and Long-Term Debt - Short-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Short-Term Debt - Outstanding	$ 64.1	$ 187.7
Short-Term Debt - Unamortized Debt Issuance Costs	0.5
Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	407.0	409.0
Standby Letters of Credit Outstanding	11.9	11.1
Draws Outstanding	$ 0.0	$ 0.0

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

The carrying value as of the balance sheet date of the current portion of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Short-Term and Long-Term Debt - Long-Term Debt (Details) - USD ($) $ in Millions				12 Months Ended
	Nov. 02, 2017	Aug. 25, 2017	Jun. 01, 2017	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-Term Debt				$ 1,439.2	$ 1,370.4
Long-Term Debt - Unamortized Debt Issuance Costs				9.5
Debt Instrument [Abstract]
Long-Term Debt Maturing in 2018				64.6
Long-Term Debt Maturing in 2019				57.6
Long-Term Debt Maturing in 2020				143.0
Long-Term Debt Maturing in 2021				97.8
Long-Term Debt Maturing in 2022				88.0
Long-Term Debt Maturing Thereafter				1,062.3
Camp Ripley Financing [Member]
Debt Instrument [Abstract]
Annual Financing Payment				$ 1.4
Financing Renewal Term (Years)				2 years
Purchase Option				$ 4.0
ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]
Debt Instrument [Abstract]
Proceeds from Issuance of Unsecured Debt			$ 80.0
Interest Rate			3.11%	3.11%
ALLETE Term Loan Variable Rate Due 2020 [Member]
Debt Instrument [Abstract]
Proceeds from Issuance of Unsecured Debt		$ 40.0
Variable Rate Basis		LIBOR
Basis Spread on Variable Rate		1.025%
ALLETE Bonds 4.07% Due April 2048 [Member]
Debt Instrument [Abstract]
Expected Proceeds from Future Issuance of Senior First Mortgage Bonds	$ 60.0
Expected Future Interest Rate	4.07%

Short-Term and Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	Aug. 25, 2017	Dec. 31, 2017	Jun. 01, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt		$ 1,513.3		$ 1,569.1
Unamortized Debt Issuance Costs		(10.0)		(11.0)
Total Long-Term Debt		1,503.3		1,558.1
Less: Due Within One Year		64.1		187.7
Net Long-Term Debt		$ 1,439.2		1,370.4
First Mortgage Bonds - 1.83% Series Due 2018 [Member]
Debt Instrument [Line Items]
Interest Rate		1.83%
Long-term Debt		$ 50.0		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
Unsecured Term Loan Variable Rate Due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 0.0		125.0
Senior Unsecured Notes 5.99% Due 2017 [Member]
Debt Instrument [Line Items]
Interest Rate		5.99%
Long-term Debt		$ 0.0		50.0
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]
Variable Rate Basis	LIBOR
Basis Spread on Variable Rate	1.025%
Long-term Debt		$ 40.0		0.0
Armenia Mountain Senior Secured Notes 3.26% Due 2024 [Member]
Debt Instrument [Line Items]
Interest Rate		3.26%
Long-term Debt		$ 65.9		74.6
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%	3.11%
Long-term Debt		$ 80.0		0.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Interest Rate		4.15%
Long-term Debt		$ 15.0		15.0
Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 69.1		$ 61.2
Minimum [Member] \| Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate		3.11%
Maximum [Member] \| Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate		5.37%

Short-Term and Long-Term Debt - Financial Covenants (Details)	12 Months Ended
	Dec. 31, 2017
Financial Covenants [Abstract]
Allowed Indebtedness to Total Capitalization Ratio	0.65
Actual Indebtedness to Total Capitalization Ratio	0.42
Compliance with Financial Covenants	ALLETE was in compliance with its financial covenants.

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

Dec. 31, 2017

USD ($)

Jul. 28, 2017

Generating Capacity Jointly Owned (MW) | MW

525

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

Generating Capacity Jointly Owned (MW) | MW

550

Coal, Rail and Shipping Contracts [Member]

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

$ 29.0

1.8

0.0

0.0

0.0

Leasing Agreements [Member]

0.0

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

14.2

12.8

9.5

7.3

6.1

Long-Term Service Agreements [Member]

30.0

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

^[1]

11.0

^[1]

0.9

^[1]

0.0

^[1]

0.0

^[1]

1.0

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

^[1]

11.0

PPAs [Member]

^[2]

104.5

^[2]

107.1

^[2]

115.0

^[2]

144.8

^[2]

144.7

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

^[2]

$ 1,667.0

[1]

Consists of long-term service agreements for wind energy facilities.

[2]

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Leasing Agreements [Line Items]
Total Lease Expense	$ 17.5	$ 17.1	$ 17.3
BNI Energy Dragline [Member]
Leasing Agreements [Line Items]
Minimum Payments in 2018	2.8
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 Thereafter	14.0
Termination Fee	$ 3.0

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

12 Months Ended

Dec. 31, 2017

USD ($)

MWh

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Jul. 28, 2017

Basin [Member] | Basin PSA (expires 2018) [Member]

100

Basin [Member] | Basin PSA (expires 2019) [Member]

100

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

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

Generating Unit Capacity (MW)

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

Great River Energy Capacity PPA Beginning June 2016 (expires May 2020) [Member] | Great River Energy [Member]

Great River Energy Capacity PPA Beginning June 2017 (expires May 2020) [Member] | Great River Energy [Member]

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

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

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

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

250

Contract Term (Years)

20 years

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

133

Shell Energy PPA (expires December 2019) [Member] | Shell Energy [Member]

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

Output Being Purchased (MWh) | MWh

Oliver Wind I PPA (expires December 2031) [Member] | Oliver Wind [Member]

Oliver Wind II PPA (expires December 2032) [Member] | Oliver Wind [Member]

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

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

Tenaska PPA [Member] | Tenaska [Member] | Wind Turbine Generators [Member] | Resource Package [Member] | MPUC [Member]

100

^[1]

250

525

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

550

Minnesota Power Output Entitlement (Percent)

50.00%

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

227.5

Minnesota Power Output Entitlement (Percent)

28.00%

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

PPA Counterparty Total Debt Outstanding | $

$ 330.0

PPA Counterparty Annual Debt Service through 2022 | $

49.0

Cost of Purchased Power | $

75.7

$ 73.3

$ 77.8

Pro Rata Share of PPA Counterparty Interest Expense | $

$ 9.4

$ 9.6

$ 10.1

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

Generating Unit Capacity (MW)

455

[1]	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota and is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired facility. (See Note 4. Regulatory Matters.)

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) kV Miles MW
Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Total Project Costs to Date - Incurred	$ 152.4
Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	560.0
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	$ 710.0
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires May 2035) [Member]
Transmission [Line Items]
Output Being Purchased (MW) \| MW	250
Manitoba Hydro [Member] \| Great Northern Transmission Line [Member]
Transmission [Line Items]
Total Project Costs to Date - Recovered	$ 67.6
Minnesota Power [Member] \| Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	300.0
Minnesota Power [Member] \| Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures, Including Past Expenditures	$ 350.0

Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MW
Environmental Remediation Costs [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance - Accrued	$ 8.0
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Additional Wind Energy Generating Capacity (MW) \| MW	200
Ozone NAAQS [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	$ 0.0
NO2 NAAQS [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	0.0
Minimum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	65.0
Maximum [Member] \| Clean Water Act - Aquatic Organisms [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	15.0
Maximum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	$ 100.0

Commitments, Guarantees and Contingencies - Other Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
ALLETE Clean Energy [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 15.4
U.S. Water Services [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.8
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	70.00%	72.00%
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	33.00%	92.00%
Annual Assessment	$ 2.0

Common Stock and Earnings Per Share - Summary of Common Stock (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of Common Stock [Line Items]
Balance, Shares	51,100	49,600
Received for Sale of Land Inventory, Shares		(100)
Received for Sale of Land Inventory, Equity		$ (8.0)
Acquisition of Non-Controlling Interest, Equity		(6.7)
Employer Contributions to Pension - Value	$ 13.5	$ 0.0	$ 0.0
Common Stock [Member]
Summary of Common Stock [Line Items]
Balance, Shares	51,117	49,560	49,075	45,929
Balance, Equity	$ 1,401.4	$ 1,295.3	$ 1,271.4	$ 1,107.6
Employee Stock Purchase Plan, Shares	12	16	18
Employee Stock Purchase Plan, Equity	$ 0.8	$ 0.9	$ 0.9
Invest Direct, Shares	257	344	383
Invest Direct, Equity	$ 19.0	$ 20.0	$ 19.0
Options and Stock Awards, Shares	22	65	43
Options and Stock Awards, Equity	$ 3.6	$ 3.7	$ 8.6
Equity Issuance Program, Shares	1,000	130	1,289
Equity Issuance Program, Equity	$ 65.7	$ 8.0	$ 69.9
Forward Sale Agreement and Issuance, Shares			1,413
Forward Sales Agreement and Issuance, Equity			$ 65.4
Contributions to RSOP, Shares	50	60
Contributions to RSOP, Equity	$ 3.5	$ 3.3
Received for Sale of Land Inventory, Shares		(130)
Received for Sale of Land Inventory, Equity		$ (8.0)
Acquisition of Non-Controlling Interest, Shares		0
Acquisition of Non-Controlling Interest, Equity		$ 4.0
Employer Contributions to Pension - Shares	216	0
Employer Contributions to Pension - Value	$ 13.5
Equity Issuance Program Shares Authorized		13,600
Equity Issuance Program Shares Available for Issuance		2,900
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share	0	0	0

Common Stock and Earnings Per Share - Forward Sale Agreement and Issuance of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares Issued			51.1	49.6
Forward Sale Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Indexed Shares		2.8
Forward Rate Per Share		$ 48.01
Shares Issued	1.4	1.4
Proceeds from Issuance of Common Stock	$ 65.4	$ 65.0

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 41.4	$ 44.9	$ 36.9	$ 49.0	$ 44.3	$ 40.3	$ 24.8	$ 45.9	$ 18.3	$ 60.4	$ 22.5	$ 39.9	$ 172.2	$ 155.3	$ 141.1
Average Common Shares													50.8	49.3	48.3
Earnings Per Share	$ 0.81	$ 0.88	$ 0.73	$ 0.97	$ 0.89	$ 0.82	$ 0.50	$ 0.93	$ 0.37	$ 1.24	$ 0.46	$ 0.85	$ 3.39	$ 3.15	$ 2.92
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE, Diluted													$ 172.2	$ 155.3	$ 141.1
Average Common Shares													51.0	49.5	48.4
Earnings Per Share	$ 0.81	$ 0.88	$ 0.72	$ 0.97	$ 0.89	$ 0.81	$ 0.50	$ 0.93	$ 0.37	$ 1.23	$ 0.46	$ 0.85	$ 3.38	$ 3.14	$ 2.92
Dilutive Securities (Shares)													0.2	0.2	0.1

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Current Income Tax Expense [Abstract]

Federal

^[1]

$ 0.0

State

^[1]

0.3

0.4

0.2

Total Current Income Tax Expense

0.3

0.4

0.2

Deferred Income Tax Expense [Abstract]

Federal

12.1

12.0

19.4

Federal - Remeasurement of Deferred Income Taxes

^[2]

(13.0)

0.0

State

15.8

8.1

6.5

Investment Tax Credit Amortization

(0.5)

(0.7)

(0.8)

Total Deferred Income Tax Expense

14.4

19.4

25.1

Total Income Tax Expense

$ 14.7

$ 19.8

$ 25.3

[1]	For the years ended December 31, 2017, 2016 and 2015, 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. The federal and state NOLs will be carried forward to offset future taxable income.
[2]	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

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

Income Before Non-Controlling Interest and Income Taxes

$ 186.9

$ 175.6

$ 166.8

Statutory Federal Income Tax Rate

35.00%

Income Taxes Computed at 35 Percent Statutory Federal Rate

$ 65.4

$ 61.5

$ 58.4

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

State Income Taxes – Net of Federal Income Tax Benefit

10.5

5.6

4.4

Regulatory Differences for Utility Plant

0.0

(0.1)

(0.6)

Production Tax Credits

(45.1)

(41.5)

(37.0)

Change in Fair Value of Contingent Consideration

0.0

(3.8)

0.0

Remeasurement of Deferred Income Taxes

^[1]

(13.0)

0.0

Deferred Income Tax Assets [Abstract]

(3.1)

(1.9)

0.1

Total Income Tax Expense

$ 14.7

$ 19.8

$ 25.3

Effective Tax Rate

7.90%

11.30%

15.20%

[1]	Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)

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

Dec. 31, 2017

Dec. 31, 2016

Employee Benefits and Compensation

$ 65.9

$ 104.6

Property Related

104.3

110.5

NOL Carryforwards

99.1

185.6

Tax Credit Carryforwards

294.3

227.4

Power Sales Agreements

35.0

59.3

Regulatory Liabilities

117.7

7.3

Gross Deferred Income Tax Assets

33.3

46.9

749.6

741.6

Deferred Income Tax Asset Valuation Allowance

(60.0)

(43.0)

Total Deferred Income Tax Assets

689.6

698.6

Deferred Income Tax Liabilities [Abstract]

Property Related

758.3

1,039.6

Regulatory Assets for Benefit Obligations

61.4

91.9

Unamortized Investment Tax Credits

32.8

33.3

Partnership Basis Differences

34.9

50.9

Regulatory Assets

32.0

25.6

Total Deferred Income Tax Liabilities

0.7

11.9

920.1

1,253.2

Net Deferred Income Taxes

^[1]

$ 230.5

$ 554.6

[1]	Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet. Additionally, see Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

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

Dec. 31, 2017

Dec. 31, 2016

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforwards

^[1]

$ 375.2

$ 485.3

Tax Credit Carryforwards

209.2

163.7

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]

289.9

294.4

Tax Credit Carryforwards

^[2]

25.6

21.0

Tax Credit Carryforwards, Valuation Allowance

$ 59.5

$ 42.7

[1]	Pre-tax amounts.
[2]	Net of a $59.5 million valuation allowance as of December 31, 2017 ($42.7 million as of December 31, 2016).

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 2.0	$ 2.4	$ 2.0
Additions for Tax Positions Related to the Current Year	0.1	0.1	0.5
Additions for Tax Positions Related to Prior Years	0.1	0.2	0.7
Reduction for Tax Positions Related to Prior Years	(0.1)	(0.3)	(0.7)
Lapse of Statute	(0.4)	(0.4)	(0.1)
Balance as of December 31	1.7	2.0	2.4
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.8
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

Reclassifications Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

$ (28.2)

$ (24.5)

$ (21.1)

5.0

(4.1)

(4.6)

Amounts Reclassified from Accumulated Other Comprehensive Loss

0.6

0.4

1.2

5.6

(3.7)

(3.4)

Unrealized Gain (Loss) on Available-for-sale Securities [Member]

(22.6)

(28.2)

(24.5)

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

(1.0)

(0.8)

(0.3)

1.1

0.0

(0.4)

Amounts Reclassified from Accumulated Other Comprehensive Loss

(0.2)

(0.1)

0.9

(0.2)

(0.5)

Defined Benefit Pension, Other Postretirement Items [Member]

(0.1)

(1.0)

(0.8)

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

^[1]

(27.2)

(23.7)

(20.7)

^[1]

3.9

(4.1)

(4.3)

Amounts Reclassified from Accumulated Other Comprehensive Loss

^[1]

0.8

0.6

1.3

^[1]

4.7

(3.5)

(3.0)

Gain (Loss) on Cash Flow Hedge [Member]

^[1]

(22.5)

(27.2)

(23.7)

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

0.0

(0.1)

0.0

0.1

Amounts Reclassified from Accumulated Other Comprehensive Loss

0.0

0.0

0.1

$ 0.0

[1]

Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 15. Pension and Other Postretirement Benefit Plans.)

Pension and Other Postretirement Benefit Plans - Contributions (Details) - USD ($) shares in Thousands, $ in Millions		12 Months Ended
	Jan. 08, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Pension - Value		$ 13.5	$ 0.0	$ 0.0
ESOP Compensation Expense		11.0	9.2	9.0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Plans - Cash		1.7	6.3	0.0
Employer Contributions to Pension - Value		$ 13.5	0.0	0.0
Defined Benefit Plan - Amendments		The non-union defined benefit pension plan does not allow further crediting of service to the plan and is closed to new participants. The Minnesota Power union defined benefit pension plan is also closed to new participants.
Expected Employer Contributions in 2018		$ 0.0
Pension Plan [Member] \| Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Defined Benefit Plans - Cash	$ 15.0
Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan - Amendments		In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to require employees to be at least age 55 with 10 years of participation in the plan. In 2014, our postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015.
Expected Employer Contributions in 2018		$ 0.0
VEBA [Member] \| Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Other Postretirement Benefit Plans		0.0	0.0	0.0
Irrevocable Grantor Trust [Member] \| Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Other Postretirement Benefit Plans		$ 0.0	$ 0.0	$ 0.0
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Pension - Shares		216	0
Employer Contributions to Pension - Value		$ 13.5
Common Stock [Member] \| Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions to Pension - Shares		200

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ (191.8)

$ (210.9)

Other Investments

53.1

55.6

Accumulated Benefit Obligation

745.4

698.8

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

743.3

709.8

Service Cost

10.2

8.1

$ 10.1

Interest Cost

32.5

33.2

29.9

Actuarial Loss

44.8

12.4

Participant Contributions

(51.0)

(44.5)

13.4

24.3

Obligation, End of Year

793.2

743.3

709.8

Fair Value, Beginning of Year

557.5

521.3

Actual Return on Plan Assets

91.6

48.8

Employer Contribution

^[1]

30.1

31.9

Funded Status, End of Year

(51.0)

(44.5)

Fair Value, End of Year

628.2

557.5

521.3

(165.0)

(185.8)

(1.4)

(163.6)

(184.4)

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

173.4

160.2

Service Cost

4.4

3.9

4.3

Interest Cost

7.7

7.4

7.2

Actuarial Loss

15.5

11.9

Participant Contributions

(12.2)

(13.1)

3.1

Plan Amendments

(1.8)

0.0

Obligation, End of Year

190.1

173.4

160.2

Fair Value, Beginning of Year

154.3

153.4

Actual Return on Plan Assets

24.5

9.6

Employer Contribution

1.3

Participant Contributions

3.1

Funded Status, End of Year

(12.2)

(13.1)

Fair Value, End of Year

171.0

154.3

$ 153.4

(19.1)

Non-Current Assets

3.0

1.4

(1.1)

Irrevocable Grantor Trust [Member] | Postretirement Health and Life [Member]

(21.0)

(19.4)

Other Investments

$ 19.2

$ 17.6

[1]	Includes Participant Contributions noted above.

Pension and Other Postretirement Benefit Plans - Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet (Details) - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ (236.2)	$ (250.4)
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)	71.2	64.6
Total Net Pension Amounts Recognized in Consolidated Balance Sheet	$ (165.0)	$ (185.8)

Pension and Other Postretirement Benefit Plans - Components of Net Periodic Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost	$ 10.2	$ 8.1	$ 10.1
Interest Cost	32.5	33.2	29.9
Expected Return on Plan Assets	(42.4)	(43.6)	(40.7)
Amortization of Loss	9.9	9.5	17.9
Amortization of Prior Service Cost	0.0	0.0	0.2
Net Pension Cost	10.2	7.2	17.4
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost	4.4	3.9	4.3
Interest Cost	7.7	7.4	7.2
Expected Return on Plan Assets	(10.5)	(11.2)	(10.9)
Amortization of Loss	0.3	0.2	0.4
Amortization of Prior Service Cost	(2.0)	(2.9)	(3.0)
Net Pension Cost	$ (0.1)	$ (2.6)	$ (2.0)

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, 2017	Dec. 31, 2016
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ (4.3)	$ 7.2
Amortization of Loss	(9.9)	(9.5)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	(14.2)	(2.3)
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	1.6	13.5
Prior Service Credit Arising During the Period	(1.8)	0.0
Amortization of Prior Service Credit	2.0	2.9
Amortization of Loss	(0.3)	(0.2)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$ 1.5	$ 16.2

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, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 793.2	$ 743.3
Accumulated Benefit Obligation	745.4	698.8
Fair Value of Plan Assets	$ 628.2	$ 557.5

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

Dec. 31, 2017

Dec. 31, 2016

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

Total Unrecognized Postretirement Health and Life Cost

$ (236.2)

$ (250.4)

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

Net Loss

^[1]

21.1

19.8

Prior Service Credit

(4.6)

(4.7)

Total Unrecognized Postretirement Health and Life Cost

$ 16.5

$ 15.1

[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, 2017

Dec. 31, 2016

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

Net Loss

^[1]

$ (21.1)

$ (19.8)

Prior Service Credit

4.6

4.7

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

(2.6)

(4.0)

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

$ (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, 2017 USD ($)
Pension [Member]
Estimated Future Benefit Payments [Abstract]
2018	$ 46.3
2019	46.2
2020	45.9
2021	45.8
2022	45.8
Years 2023 - 2027	228.0
Postretirement Health and Life [Member]
Estimated Future Benefit Payments [Abstract]
2018	9.2
2019	9.5
2020	9.6
2021	9.6
2022	9.6
Years 2023 - 2027	$ 49.7

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, 2017 USD ($)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 12.0
Prior Service Credit	0.0
Total Pension and Postretirement Health and Life Cost (Credit)	12.0
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	0.7
Prior Service Credit	(1.8)
Total Pension and Postretirement Health and Life Cost (Credit)	$ (1.1)

Pension and Other Postretirement Benefit Plans - Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.53%	4.72%	4.30%
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.57%	4.73%	4.33%
Pension [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate		4.53%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	7.50%	8.00%	8.00%
Pension [Member] \| Minimum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	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	3.96%
Rate of Compensation Increase	4.10%	4.30%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	4.30%	4.30%	4.30%
Postretirement Health and Life [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	3.86%	4.57%
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%	6.40%	6.40%
Postretirement Health and Life [Member] \| Maximum [Member]
Health Care Trend Rates [Abstract]
Trend Rate	6.73%	7.00%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	7.50%	8.00%	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, 2017 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Effect of One Percent Increase on Total of Postretirement Health and Life Service and Interest Cost	$ 1.9
Effect of One Percent Increase on Postretirement Health and Life Obligation	23.4
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.5)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (19.3)

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

Dec. 31, 2017

Dec. 31, 2016

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

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

100.00%

0.0

Pension [Member] | Equity Securities [Member]

100.00%

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

53.00%

49.00%

Pension [Member] | Debt Securities [Member]

56.00%

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

38.00%

39.00%

Pension [Member] | Private Equity [Member]

35.00%

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

Pension [Member] | Real Estate [Member]

5.00%

7.00%

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

4.00%

5.00%

9.00%

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

^[1]

100.00%

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

^[2]

100.00%

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

^[1]

64.00%

60.00%

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

^[2]

60.00%

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

^[1]

31.00%

34.00%

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

^[2]

37.00%

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

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

^[1]

5.00%

6.00%

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

^[1]

0.00%

Performance Shares [Member]

^[2]

3.00%

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

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures, Activity in Level 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 40.6	$ 43.3
Actual Return on Plan Assets	7.1	5.0
Purchases, Sales, and Settlements – Net	(14.5)	(7.7)
Ending Balance	33.2	40.6
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	25.6	28.9
Actual Return on Plan Assets	1.7	2.3
Purchases, Sales, and Settlements – Net	(1.8)	(5.6)
Ending Balance	25.5	25.6
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	9.5	12.0
Actual Return on Plan Assets	2.6	1.4
Purchases, Sales, and Settlements – Net	(3.9)	(3.9)
Ending Balance	$ 8.2	$ 9.5

Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Stock Ownership Plan [Abstract]
ESOP Employer Loan	In 1990, the ESOP issued a $75.0 million note to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our common stock. The note matured in December 2015.
ESOP Compensation Expense	$ 11.0	$ 9.2	$ 9.0
ESOP Shares, Allocated	1.4	1.6	1.8
ESOP Shares, Unallocated	0.0	0.0	0.0
ESOP Shares, Total	1.4	1.6	1.8
ESOP Shares, Fair Value of Unallocated Shares	$ 0.0	$ 0.0	$ 0.0

Employee Stock and Incentive Plans - Stock-Based Compensation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2017 shares
Non-Qualified Stock Options [Member]
Stock-based Compensation [Line Items]
Annual Vesting Percent	33.33%
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)	1.0
Shares Available for Issuance	0.8

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 3.1	$ 2.6	$ 2.6
Income Tax Benefit	0.9	1.1	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	2.1	1.8	1.8
Unrecognized Compensation Cost	$ 2.4
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	$ 1.0	$ 0.8	$ 0.8
Unrecognized Compensation Cost	$ 1.0
Weighted-Average Period for Recognition (Years/Months)	1 year 8 months

Employee Stock and Incentive Plans - Non-Qualified Stock Options (Details) - Non-Qualified Stock Options [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of Options [Roll Forward]
Outstanding as of January 1	4,357	39,654	66,279
Exercised	(4,357)	(35,297)	(24,456)
Forfeited	0	0	(2,169)
Outstanding as of December 31	0	4,357	39,654
Exercisable as of December 31	0	4,357	39,654
Weighted-Average Exercise Price [Abstract]
Outstanding as of January 1	$ 40.29	$ 44.39	$ 44.39
Exercised	40.29	44.89	44.52
Forfeited	0.00	0	42.93
Outstanding as of December 31	0.00	40.29	44.39
Exercisable as of December 31	$ 0.00	$ 40.29	$ 44.39
Cash Received from Non-Qualified Stock Options Exercised	$ 0.3
Total Intrinsic Value of Options Exercised	$ 0.1	$ 0.5	$ 0.2

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, 2018

Jan. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

127,898

127,580

119,540

119,635

^[1]

50,729

57,189

43,583

Unearned Grant Award

(40,801)

(42,126)

(36,670)

(9,610)

(7,023)

(7,008)

Performance Period (Years)

127,898

127,580

119,540

3 years

Weighted-Average Grant Date Fair Value [Abstract]

$ 58.23

$ 52.56

$ 52.72

$ 48.26

^[1]

62.90

52.43

58.95

Unearned Grant Award

46.27

52.70

45.41

58.29

53.45

53.49

Restricted Stock Units [Member]

$ 58.23

$ 52.56

$ 52.72

55,248

54,728

57,694

53,888

^[2]

21,241

20,351

26,702

(17,281)

(19,661)

(19,464)

(3,440)

(3,656)

(3,432)

Performance Period (Years)

55,248

54,728

57,694

3 years

Weighted-Average Grant Date Fair Value [Abstract]

$ 56.18

$ 51.79

$ 49.86

$ 44.47

^[2]

62.20

50.25

54.81

49.72

44.33

41.44

56.00

52.87

51.52

Subsequent Event [Member] | Performance Shares [Member]

$ 56.18

$ 51.79

$ 49.86

35,894

Performance Period (Years)

(58,293)

3 years

Granted, Grant Date Fair Value

$ 2.9

Awarded, Grant Date Fair Value

$ 3.5

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

14,569

Granted, Grant Date Fair Value

(12,766)

$ 1.1

Awarded, Grant Date Fair Value

$ 0.7

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

Business Segments (Details)
$ in Millions

3 Months Ended

12 Months Ended

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, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Description of Effect on Previously Reported Segment Information for Change in Composition of Reportable Segments

Number of Reportable Segments

$ 337.9

$ 362.5

$ 353.3

$ 365.6

$ 341.5

$ 349.6

$ 314.8

$ 333.8

$ 380.6

$ 462.5

$ 323.3

$ 320.0

$ 1,419.3

$ 1,339.7

$ 1,486.4

41.4

$ 44.9

$ 36.9

$ 49.0

44.3

$ 40.3

$ 24.8

$ 45.9

$ 18.3

$ 60.4

$ 22.5

$ 39.9

172.2

155.3

141.1

Operating Expenses – Other

177.5

195.8

170.0

(0.7)

(10.3)

(36.3)

Deferred Income Tax Expense (Benefit) due to the Remeasurement of Deferred Income Taxes

67.8

70.3

64.9

Equity Earnings in ATC

22.5

18.5

16.3

^[1]

(13.0)

0.0

14.7

19.8

25.3

^[2]

5,080.0

4,876.9

5,080.0

4,876.9

Regulated Operations [Member]

$ 266.5

247.8

Number of Operating Segments

$ 1,063.8

1,000.7

991.2

^[3],[4]

128.4

135.5

131.6

132.6

154.3

135.1

Deferred Income Tax Expense (Benefit) due to the Remeasurement of Deferred Income Taxes

^[3]

57.0

52.1

53.9

Equity Earnings in ATC

22.5

18.5

16.3

0.0

^[5],[6]

27.2

5.9

24.4

^[2]

3,886.6

3,823.9

3,886.6

3,823.9

177.1

121.8

^[7]

80.5

262.1

^[3],[4]

41.5

13.4

29.9

Operating Expenses – Other

23.4

22.3

18.7

^[8]

0.0

3.3

0.0

Deferred Income Tax Expense (Benefit) due to the Remeasurement of Deferred Income Taxes

^[3]

4.2

5.8

3.3

(23.6)

^[6]

(14.2)

8.1

21.0

600.5

566.0

600.5

566.0

ALLETE Clean Energy [Member] | Wind Construction Project [Member]

56.1

106.9

197.7

151.8

137.5

119.8

^[3],[4]

10.7

1.5

0.9

9.8

8.9

7.3

Deferred Income Tax Expense (Benefit) due to the Remeasurement of Deferred Income Taxes

^[3]

1.6

1.7

1.4

(9.2)

^[6]

(7.8)

1.4

0.9

$ 292.4

264.1

292.4

264.1

Corporate and Other [Member]

$ 4.4

3.7

Number of Operating Segments

Land in Minnesota (Acres) | a

5,000

$ 123.2

121.0

113.3

^[3],[4]

(8.4)

4.9

(21.3)

Operating Expenses – Other

11.7

10.3

8.9

(0.7)

^[8]

(13.6)

^[3]

36.3

^[8]

Deferred Income Tax Expense (Benefit) due to the Remeasurement of Deferred Income Taxes

^[3]

10.3

14.5

8.6

19.8

^[5],[6]

9.5

4.4

(21.0)

$ 300.5

$ 222.9

300.5

222.9

28.9

15.4

Eliminations [Member]

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

^[3]

(5.3)

(3.8)

$ (2.3)

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

0.0

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

14.0

(15.0)