Accounts Receivable (Less Allowance of $3.1 and $1.0)

$ 27.5

$ 97.0

122.5

121.2

Inventories – Net

104.2

117.1

Prepayments and Other

40.3

35.7

Total Current Assets

294.5

371.0

Goodwill and Intangible Assets – Net

3,741.2

3,669.1

Regulatory Assets

359.6

372.0

Investment in ATC

135.6

124.5

Other Investments

55.6

74.6

213.4

215.2

Long-Term Debt Due Within One Year

106.5

68.1

Total Assets

^[1]

4,906.4

4,894.5

Current Liabilities [Abstract]

Accounts Payable

74.0

88.8

Accrued Taxes

46.5

44.0

Accrued Interest

17.6

18.6

187.7

35.7

Notes Payable

0.0

1.6

Total Current Liabilities

73.7

86.1

399.5

274.8

Long-Term Debt

1,370.4

1,556.7

Deferred Income Taxes

584.1

579.8

Regulatory Liabilities

125.8

105.0

Defined Benefit Pension and Other Postretirement Benefit Plans

210.9

206.8

Other Non-Current Liabilities

322.7

349.0

Total Liabilities

3,013.4

3,072.1

Commitments, Guarantees and Contingencies (Note 11)

ALLETE's Equity [Abstract]

Common Stock Without Par Value, 80.0 Shares Authorized, 49.6 and 49.1 Shares Issued and Outstanding

1,295.3

1,271.4

Accumulated Other Comprehensive Loss

(28.2)

(24.5)

Retained Earnings

625.9

573.3

Total ALLETE Equity

1,893.0

1,820.2

Non-Controlling Interest in Subsidiaries

0.0

2.2

Total Equity

1,893.0

1,822.4

Total Liabilities and Equity

$ 4,906.4

$ 4,894.5

[1]

As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been reclassified to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 3.1	$ 1.0
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	49.6	49.1
Common Stock, Shares Issued	49.6	49.1

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Operating Revenue	$ 1,339.7	$ 1,486.4	$ 1,136.8
Operating Expenses [Abstract]
Fuel and Purchased Power	332.9	328.1	356.1
Transmission Services	65.2	54.1	45.6
Cost of Sales	144.7	302.3	77.9
Operating and Maintenance	334.1	333.5	287.1
Depreciation and Amortization	195.8	170.0	135.7
Taxes Other Than Income Taxes	53.8	51.4	45.6
Other	(10.3)	36.3	0.0
Total Operating Expenses	1,116.2	1,275.7	948.0
Operating Income	223.5	210.7	188.8
Other Income (Expense) [Abstract]
Interest Expense	(70.3)	(64.9)	(54.8)
Equity Earnings in ATC	18.5	16.3	19.6
Other	3.9	4.7	8.6
Total Other Expense	(47.9)	(43.9)	(26.6)
Income Before Non-Controlling Interest and Income Taxes	175.6	166.8	162.2
Income Tax Expense	19.8	25.3	36.7
Net Income	155.8	141.5	125.5
Less: Non-Controlling Interest in Subsidiaries	0.5	0.4	0.7
Net Income Attributable to ALLETE	$ 155.3	$ 141.1	$ 124.8
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	49.3	48.3	42.9
Diluted (Shares)	49.5	48.4	43.1
Basic Earnings Per Share of Common Stock	$ 3.15	$ 2.92	$ 2.91
Diluted Earnings Per Share of Common Stock	3.14	2.92	2.90
Dividends Per Share of Common Stock	$ 2.08	$ 2.02	$ 1.96

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Comprehensive Income [Abstract]
Net Income	$ 155.8	$ 141.5	$ 125.5
Other Comprehensive Income (Loss) [Abstract]
Unrealized Loss on Securities - Net of Income Tax Benefit of $(0.2), $(0.3) and $(0.2)	(0.2)	(0.5)	(0.2)
Unrealized Gain on Derivatives - Net of Income Tax Expense of $–, $0.1 and $0.1	0.0	0.1	0.2
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Tax Benefit of $(2.4), $(2.2) and $(2.8)	(3.5)	(3.0)	(4.0)
Total Other Comprehensive Loss	(3.7)	(3.4)	(4.0)
Total Comprehensive Income	152.1	138.1	121.5
Less: Non-Controlling Interest in Subsidiaries	0.5	0.4	0.7
Total Comprehensive Income Attributable to ALLETE	$ 151.6	$ 137.7	$ 120.8

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Unrealized Loss on Securities, Income Tax Benefit	$ (0.2)	$ (0.3)	$ (0.2)
Unrealized Gain on Derivatives, Income Tax Expense	0.0	0.1	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Tax Benefit	$ (2.4)	$ (2.2)	$ (2.8)

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Operating Activities

Net Income

$ 155.8

$ 141.5

$ 125.5

Allowance for Funds Used During Construction – Equity

(2.1)

(3.3)

(7.8)

Income from Equity Investments – Net of Dividends

(5.7)

(1.8)

(2.6)

Impairment of Real Estate

^[1]

0.0

36.3

0.0

Change in Fair Value of Contingent Consideration

^[2]

3.3

^[3]

0.0

^[4]

(13.6)

0.0

Gain on Sales of Investments and Property, Plant and Equipment

(6.0)

(0.2)

Depreciation Expense

190.6

165.9

135.7

Amortization of Power Sales Agreements

(22.3)

(23.2)

(12.7)

Amortization of Other Intangible Assets and Other Assets

10.3

5.6

0.7

Deferred Income Tax Expense

19.4

25.1

32.7

Share-Based Compensation Expense

2.6

2.3

ESOP Compensation Expense

2.5

9.0

9.1

Defined Benefit Pension and Other Postretirement Benefit Expense

4.6

15.4

12.8

Bad Debt Expense

4.1

1.6

1.8

Changes in Operating Assets and Liabilities

Accounts Receivable

(4.7)

1.1

(3.5)

Inventories

13.3

(22.1)

(17.5)

Prepayments and Other

(6.9)

3.7

4.8

Accounts Payable

6.5

(19.3)

10.9

Other Current Liabilities

(13.8)

5.1

(3.5)

Cash Contributions to Defined Benefit Pension Plans

6.3

0.0

Changes in Regulatory and Other Non-Current Assets

(10.7)

0.6

(21.3)

Changes in Regulatory and Other Non-Current Liabilities

11.1

(3.5)

2.6

Cash from Operating Activities

332.0

340.1

269.8

Investing Activities

Proceeds from Sale of Available-for-sale Securities

9.0

1.7

3.6

Payments for Purchase of Available-for-sale Securities

(9.4)

(2.3)

(5.0)

Acquisitions of Subsidiaries – Net of Cash Acquired

(5.9)

(333.3)

(60.3)

Investment in ATC

(5.4)

(1.6)

(3.9)

Changes to Other Investments

4.4

3.1

33.0

Additions to Property, Plant and Equipment

(265.6)

(286.8)

(572.8)

Construction Costs for Development Project

0.0

(25.7)

Cash in Escrow for Acquisition

0.0

5.4

Proceeds from Sale of Property, Plant and Equipment

0.7

0.4

0.0

Changes in Restricted Cash

(4.0)

0.0

Cash for Investing Activities

(276.2)

(618.8)

(625.7)

Financing Activities

Proceeds from Issuance of Common Stock

30.9

161.2

200.6

Proceeds from Issuance of Long-Term Debt

4.8

324.5

375.0

Changes in Restricted Cash

7.0

8.5

(1.8)

Changes in Notes Payable

(1.6)

(2.1)

3.7

Repayments of Long-Term Debt

(54.8)

(160.2)

(134.5)

Acquisition of Non-Controlling Interest

(8.0)

0.0

(6.0)

Construction Deposits Received for Development Project

0.0

54.3

Dividends on Common Stock

(102.7)

(97.9)

(83.8)

Other Financing Activities

(0.9)

(4.1)

(3.1)

Cash from (for) Financing Activities

(125.3)

229.9

404.4

Change in Cash and Cash Equivalents

(69.5)

(48.8)

48.5

Cash and Cash Equivalents at Beginning of Period

97.0

145.8

97.3

Cash and Cash Equivalents at End of Period

$ 27.5

$ 97.0

$ 145.8

[1]	See Impairment of Long-Lived Assets.
[2]	See Goodwill and Intangible Assets.
[3]	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 January 2014.
[4]	See Note 9. Fair Value.

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, 2013	$ 1,342.9	$ 489.1	$ (17.1)	$ (14.3)	$ 885.2	$ 0.0
Consolidated Statement of Equity [Roll Forward]
Recognition of Non-Controlling Interest	7.1					7.1
Comprehensive Income
Net Income	125.5	124.8				0.7
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities	(0.2)		(0.2)
Unrealized Gain on Derivatives	0.2		0.2
Defined Benefit Pension and Other Postretirement Plans	(4.0)		(4.0)
Total Comprehensive Income	121.5
Common Stock Issued	222.4				222.4
Dividends Declared	(83.8)	(83.8)
ESOP Shares Earned	7.1			7.1
Acquisition of Non-Controlling Interest	(6.0)					(6.0)
Ending 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 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 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
Common Stock Retired	(8.0)				(8.0)
Dividends Declared	(102.7)	(102.7)
Acquisition of Non-Controlling Interest	(6.7)				(4.0)	(2.7)
Ending Balance at Dec. 31, 2016	$ 1,893.0	$ 625.9	$ (28.2)	$ 0.0	$ 1,295.3	$ 0.0

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

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 parts 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 from PSAs under various durations. In addition, ALLETE Clean Energy constructed and sold a 107 MW wind energy facility in 2015. On January 3, 2017, ALLETE Clean Energy announced that it will develop another wind energy facility of up to 50 MW after securing a 25‑year PSA. The PSA includes an option for the counterparty to purchase the facility upon development completion; construction is expected to begin in 2018.

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, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2016, 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 while also pursuing a bulk sale of our entire portfolio. Proceeds from a bulk sale would be strategically deployed to support growth in 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	2016		2015		2014
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$68.2		$59.0		$51.3
Cash Paid During the Period for Income Taxes		$0.5		$0.4		$5.1
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(22.0)		$(40.6)			$21.7
Capitalized Asset Retirement Costs		$3.7		$12.4	$22.4
Camp Ripley Solar Project Financing		$15.0	—		—
AFUDC–Equity		$2.1		$3.3		$7.8
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	—		—		$19.5
Contingent Consideration	—			$35.7	—
ALLETE Common Stock Received for Sale of 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 problems and such other factors that, in our judgment, deserve recognition in estimating losses.



Accounts Receivable
As of December 31	2016		2015
Millions
Trade Accounts Receivable
Billed		$106.5		$105.3
Unbilled	19.1		16.9
Less: Allowance for Doubtful Accounts	3.1		1.0
Total Accounts Receivable		$122.5		$121.2

Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to 9 Large Power Customers. Receivables from these customers totaled $9.5 million as of December 31, 2016 ($9.2 million at December 31, 2015). 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 8 percent of consolidated operating revenue in 2016 (8 percent in 2015; 12 percent in 2014).

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

Available-for-Sale Securities. Available-for-sale 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 the share price trends and the impact of overall market conditions. (See Note 8. Investments.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Inventories – Net. Inventories are stated at the lower of cost or market. 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 are carried at an average cost, first-in, first-out or specific identification basis. Fuel for generation is carried at an average cost basis. Certain other inventories, including capital spares, are carried at specific cost.



Inventories – Net
As of December 31	2016			2015
Millions
Fuel (a)		$43.9			$58.1
Materials and Supplies	48.7			49.1
Raw Materials	2.9			2.7
Work in Progress	1.0			—
Finished Goods	8.6			7.5
Reserve for Obsolescence	(0.9		)	(0.3		)
Total Inventories		$104.2			$117.1


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



Prepayments and Other Current Assets
As of December 31	2016		2015
Millions
Deferred Fuel Adjustment Clause		$18.6		$10.6
Restricted Cash (a)	2.2		5.6
Other	19.5		19.5
Total Prepayments and Other Current Assets		$40.3		$35.7


(a)	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements 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 non-utility property, plant and equipment are recognized when they are retired or otherwise disposed. When utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for component depreciation. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 2. Property, Plant and Equipment.)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. In 2015, Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to natural gas which were actions included in Minnesota Power’s MPUC-approved 2013 IRP. In an order dated July 18, 2016, the MPUC approved Minnesota Power’s 2015 IRP with modifications which contains the next steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2, which occurred 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 directs Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, and on October 19, 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 or Boswell Units 1 and 2, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2, or the conversion of Laskin. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives. (See Note 4. Regulatory Matters.) The net book values for Taconite Harbor and Boswell Units 1 and 2 as of December 31, 2016, were approximately $90 million and $30 million, respectively. We would seek recovery in a general rate case of additional depreciation expense as a result of material changes in useful lives.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 or 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 which, if consummated, would likely result in sales proceeds below the book value of the real estate assets. Proceeds from such a sale would be strategically deployed to support growth in 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 2016 and 2014, impairment analyses of estimated undiscounted future net cash flows were conducted and 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 2016 or 2014.

ALLETE Clean Energy’s Wind Turbine Generators. During our annual impairment assessment of ALLETE Clean Energy’s goodwill (see Goodwill), management determined an impairment of goodwill was required primarily due to lower estimated energy prices in periods not under PSAs. As a result of these lower estimated energy prices in periods not under PSAs, the Company has reviewed 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. The significant assumptions utilized in the undiscounted future cash flows were consistent with those utilized in our annual goodwill impairment assessment. There were no indicators of impairment in 2015 or 2014.

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 of the date of our annual goodwill impairment testing in 2016, the ALLETE Clean Energy and U.S. Water Services reporting units 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 compare 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 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.

ALLETE Clean Energy. Our annual impairment analysis indicated the Step 2 analysis was necessary. Step 2 of the impairment test is performed to measure the impact of the goodwill impairment loss. Step 2 requires that the implied fair value of the reporting unit’s goodwill be compared to the carrying amount of that goodwill. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess, up to the entire amount of goodwill. After performing Step 2, it was determined that the implied value of goodwill was less than the carrying amount, resulting in a non-cash impairment charge of $3.3 million in 2016, which is presented within Operating Expenses – Other in the Consolidated Statement of Income (none in 2015 or 2014). The impairment charge represented the entire carrying amount of goodwill for ALLETE Clean Energy. The facts and circumstances that led to an impairment of goodwill primarily relate to lower estimated energy prices in periods not under PSAs. The fair value of the reporting unit was determined based on a discounted cash flow model. Significant assumptions in the discounted cash flow model included annual generation, operation and maintenance expenses, income tax rates, discount rates ranging from 8.25 percent to 9.25 percent and forward energy price curves. ALLETE Clean Energy’s goodwill was primarily related to the acquisition of Storm Lake II in January 2014.

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 2016 indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and no impairment existed (none in 2015). Significant assumptions in the discounted cash flow model included a discount rate of 10.75 percent, cash flow forecasts through 2021, annual revenue growth rates ranging from 8 percent to 11 percent and a terminal growth rate of 5.0 percent. Forecasted annual revenue growth assumes an increase in market share and growth in the industry. The calculated fair value of equity for the U.S. Water Services reporting unit exceeds carrying value by less than 10 percent. If U.S. Water Services fails to meet expected cash flow forecasts by a nominal margin, the results of future impairment tests could result in an impairment of goodwill. Additionally, an increase in interest rates could have an adverse impact on the discount rate used in the Company’s valuation under the income approach, potentially resulting in an impairment of goodwill.

Intangible Assets. Intangible assets include customer relationships, patents, non-compete agreements and trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents and non-compete agreements, which are amortized on a straight-line basis with estimated remaining useful lives ranging from approximately 2 years to approximately 21 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 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 2016 indicated that the estimated fair value of trademarks and trade names exceeded the asset carrying values. As a result, no impairment was recorded in 2016 (none in 2015).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Non-Current Assets
As of December 31	2016		2015
Millions
Contract Payment (a)		$29.6	—
Finance Receivable (b)	11.5		—
Restricted Cash (c)	8.6			$8.1
Other	56.8		60.0
Total Other Non-Current Assets		$106.5		$68.1


(a)	Contract Payment includes a $31.0 million 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)

On September 22, 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 ALLETE Clean Energy’s loan agreements and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.



Other Current Liabilities
As of December 31	2016		2015
Millions
Customer Deposits		$5.4		$15.1
Power Sales Agreements	24.6		23.3
Other	43.7		47.7
Total Other Current Liabilities		$73.7		$86.1



Other Non-Current Liabilities
As of December 31	2016		2015
Millions
Asset Retirement Obligation		$136.6		$131.4
Power Sales Agreements	113.8		138.1
Contingent Consideration (a)	25.0		36.6
Other	47.3		42.9
Total Other Non-Current Liabilities		$322.7		$349.0


(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 service 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. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is billed to customers pursuant to the fuel adjustment clause.

Revenue from cost recovery riders (transmission, renewable and environmental improvement) is accounted for in accordance with the accounting standards 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 commission, 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 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 and net purchases in Fuel and Purchased Power 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 wind energy facilities acquisitions in 2014 and 2015, ALLETE Clean Energy 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. In 2016, we recognized $22.3 million of non-cash revenue amortization relating to the difference between contract prices and estimated market prices as an increase in Operating Revenue on the Consolidated Statement of Income ($23.2 million in 2015; $12.7 million in 2014).

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. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.



Operating Expenses – Other
Year Ended December 31	2016			2015		2014
Millions
Impairment of Real Estate (a)	—				$36.3	—
Impairment of Goodwill (b)		$3.3		—		—
Change in Fair Value of Contingent Consideration (c)	(13.6		)	—		—
Total Operating Expenses – Other	$(10.3)				$36.3	—


(a)	See Impairment of Long-Lived Assets.


(b)	See Goodwill and Intangible Assets.


(c)	See Note 9. Fair Value.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 the accounting standards 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 the accounting standards 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.)

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 Standards.

Revenue from Contracts with Customers. In May 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict 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. The Company is considering the impact of the new guidance on its ability to recognize revenue from certain contracts where collectibility is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). The guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018.

Amendments to the Consolidation Analysis. In February 2015, the FASB issued revised guidance which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The new standard affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our Consolidated Financial Statements.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Standards (Continued)

Presentation of Debt Issuance Costs. In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented on the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability. This guidance was adopted in the first quarter of 2016 resulting in the reclassification of unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. The effect of the adoption decreased Total Assets and Total Liabilities on the Consolidated Balance Sheet by $12.6 million as of December 31, 2015.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). In May 2015, the FASB issued an accounting standard update which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share (or its equivalent) practical expedient. The guidance applies to investments for which there is not a readily determinable fair value (market quote) or the investment is in a mutual fund without a publicly available net asset value. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our Consolidated Financial Statements.

Simplifying the Measurement of Inventory. In July 2015, the FASB issued an accounting standard 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 is effective for the Company beginning in the first quarter of 2017; early adoption is permitted. The adoption of this update is not expected to have a material impact on our Consolidated Financial Statements.

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 updated guidance. The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. The Company is evaluating the impact of the amended lease guidance on the Company’s 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 is effective for the Company beginning 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.

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. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018, and the guidance will result in changes to the Company’s Consolidated Statement of Cash Flows relating to debt prepayments, contingent consideration payments, proceeds from insurance settlements, proceeds from corporate-owned life insurance policies and distributions received from equity method investees.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Standards (Continued)

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. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018, and 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.

Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued an accounting standard update to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. The guidance requires a goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The accounting guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis. The Company is evaluating the impact of the amended guidance on the Company’s Consolidated Financial Statements.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2016			2015
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,437.0			$4,336.7
Construction Work in Progress	84.2			101.2
Accumulated Depreciation	(1,426.1		)	(1,323.8		)
Regulated Operations – Net	3,095.1			3,114.1
ALLETE Clean Energy
Property, Plant and Equipment in Service	472.3			467.3
Construction Work in Progress (a)	101.0			4.0
Accumulated Depreciation	(41.0		)	(24.0		)
ALLETE Clean Energy – Net	532.3			447.3
U.S. Water Services
Property, Plant and Equipment in Service	19.5			15.6
Accumulated Depreciation	(6.9		)	(3.4		)
U.S. Water Services – Net	12.6			12.2
Corporate and Other (b)
Property, Plant and Equipment in Service	179.8			165.6
Construction Work in Progress	2.8			4.5
Accumulated Depreciation	(81.4		)	(74.6		)
Corporate and Other – Net	101.2			95.5
Property, Plant and Equipment – Net		$3,741.2			$3,669.1


(a)	The increase in ALLETE Clean Energy’s construction work in progress primarily relates to deposits for WTGs. The WTGs will be utilized as ALLETE Clean Energy develops future projects.


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

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

NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)



Estimated Useful Lives of Property, Plant and Equipment
Regulated Operations		ALLETE Clean Energy (a)	5 to 35 years
Generation	10 to 50 years	U.S. Water Services	3 to 39 years
Transmission	44 to 67 years	Corporate and Other	3 to 47 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 costs 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 commissions 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 the guidance for AROs. (See Note 4. Regulatory Matters.)



Asset Retirement Obligations
Millions
Obligation as of December 31, 2014		$109.2
Accretion	7.3
Liabilities Recognized (a)	5.1
Liabilities Settled	(2.6		)
Revisions in Estimated Cash Flows	12.4
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


(a)	The increase in 2015 is related to the ALLETE Clean Energy wind energy facilities acquisitions in 2015. (See Note 6. Acquisitions.)

Jointly-Owned Facilities and Projects

12 Months Ended

Dec. 31, 2016

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 is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists 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.

NOTE 3. JOINTLY-OWNED FACILITIES AND PROJECTS (Continued)

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, 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
As of December 31, 2015
Boswell Unit 4		$668.2		$195.0		$6.9	80
CapX2020 Projects	101.1		3.4		—		9.3 - 14.7
Total		$769.3		$198.4		$6.9

Regulatory Matters

12 Months Ended

Dec. 31, 2016

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, FERC and PSCW.

2010 Minnesota General Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio. 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 $97.1 million in 2016 ($89.6 million in 2015; $71.8 million in 2014).

2016 Minnesota General Rate Case. On November 2, 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 seeks a return on equity of 10.25 percent and a 53.8 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $55 million in additional revenue. On December 12, 2016, due to a change in its electric sales forecast, 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; Minnesota Power will file to update its final retail rate increase request by February 28, 2017, and expects the final retail rate increase request to decrease similar to the interim rate proposal. In orders dated December 30, 2016, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017. As part of this rate increase request, we are seeking an extension of the recovery period for Boswell to better reflect recent environmental investments at the facility and mitigate rate increases for our customers. If approved, annual depreciation expense will be reduced by approximately $25 million. If the requested recovery period extension is not approved, we would expect final rates to be increased by a similar amount. We cannot predict the level of final rates that may be authorized by the MPUC.

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking law in June 2015 which established that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. In November 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. The rate proposal was revenue and cash flow neutral to Minnesota Power. In an order dated March 23, 2016, the MPUC dismissed the petition without prejudice, providing Minnesota Power the option to refile the petition with additional information or file a new petition. On June 30, 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. In an order dated December 21, 2016, the MPUC approved a reduction in rates for EITE customers and determined that cost recovery will be addressed in a separate proceeding. Minnesota Power provided additional information on cost recovery allocation methods in a December 30, 2016, compliance filing.

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)

In April 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. No termination notice may be given for this contract prior to June 30, 2025. The electric service agreements with SWL&P and one other municipal customer are effective through January 31, 2020 and June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to January 31, 2017. The other municipal customer provided termination notice for its contract on June 30, 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 (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.

In September 2015, Minnesota Power amended its wholesale electric contracts with 14 municipal customers, extending the contract terms through December 31, 2024. No termination notices may be given prior to December 31, 2021. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will not increase by more than two percent or decrease by more than one percent from the previous year’s capacity charge and will be determined using a cost-based formula methodology. 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 an order dated February 3, 2016, the MPUC approved Minnesota Power’s updated billing factor 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 June 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 Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission 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. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated December 21, 2016, which 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. The approval is on a provisional basis pending the outcome of Minnesota Power’s 2016 general rate case.

In an order dated November 30, 2016, 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 has created a regulatory liability, and recorded a reduction in operating revenue for $15.0 million. 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. On December 20, 2016, Minnesota Power submitted a request for reconsideration with the MPUC. On February 9, 2017, the MPUC decided to reconsider its November 30, 2016 order and will be requesting further comments. Minnesota Power will provide further support on its position.

Prior to the November 30, 2016, MPUC order, Minnesota Power accounted for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. 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 had 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 were included in the ALLETE consolidated group.

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, but Minnesota Power expects to file its first solar factor filing in 2017 for recovery of costs related to the Camp Ripley solar project and community solar garden project.

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 an order dated December 21, 2016; however, Minnesota Power plans to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.)

Boswell Remaining Life Petition. In November 2015, Minnesota Power filed a petition with the MPUC for approval to extend Boswell’s remaining life to 2050 for all units and utilize the existing environmental improvement rider to credit a portion of the depreciation expense savings to customers. The extension request was based on the significant multi-emissions retrofit work done at Boswell Unit 3 and Boswell Unit 4. For efficiency, Minnesota Power withdrew its petition to extend Boswell’s remaining life as Minnesota Power decided to incorporate the life extension in its 2016 general rate case. In an order dated September 23, 2016, the MPUC approved Minnesota Power’s request to withdraw the petition. On February 1, 2017, Minnesota Power filed its 2017 remaining life depreciation petition in which it requested extending Boswell’s remaining life to 2050.

Annual Automatic Adjustment (AAA) of Charges. In an order dated June 2, 2016, the MPUC approved Minnesota Power’s AAA filings made in 2012 and 2013. The MPUC deferred action for 90 days on the AAA filing made in 2014 to review and confirm coal transportation costs and terms of service, which was subsequently completed on September 6, 2016, resulting in final approval of the filing. Minnesota Power’s AAA filings made in 2015 and 2016 are pending MPUC approval, and represent approximately $350 million in retail fuel cost recovery collected but subject to refund. These filings have historically been approved, and Minnesota Power currently expects full recovery of amounts represented by the AAA filings, although we cannot predict the outcome of the filings at the MPUC.

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order that allows for a 10.9 percent return on common equity. On June 28, 2016, SWL&P filed a rate increase request with the PSCW requesting an average overall increase of 3.1 percent for retail customers (a 3.5 percent increase in electric rates, a 1.3 percent decrease in natural gas rates and a 7.8 percent increase in water rates). The rate filing seeks an overall return on equity of 10.9 percent and a 55 percent equity ratio. On an annualized basis, the requested rate increase would generate approximately $2.7 million in additional revenue. Hearings are expected to be scheduled in the first half of 2017. The Company anticipates new rates will take effect during the second quarter of 2017. We cannot predict the level of rates that may be approved by the PSCW.

Integrated Resource Plan (IRP). In 2013, the MPUC approved Minnesota Power’s 2013 IRP which detailed its EnergyForward strategic plan. Significant elements of the EnergyForward plan include major wind investments in North Dakota completed in 2014, the installation of emissions control technology at Boswell Unit 4 completed in December 2015, planning for the proposed GNTL, the conversion of Laskin from coal to natural gas completed in June 2015 and the retirement of Taconite Harbor Unit 3 completed in May 2015. In September 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 the next steps in Minnesota Power’s EnergyForward 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 an order dated July 18, 2016, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepts Minnesota Power’s plans for Taconite Harbor, directs Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, requires an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and requires Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. On October 19, 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018 as the latest step in its EnergyForward strategic plan. Minnesota Power’s next IRP must be filed by February 1, 2018.

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. The GNTL is subject to various federal and state regulatory approvals. In 2013, a certificate of need application was filed with the MPUC which was approved in a June 2015 order. Based on this order, 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 factor filings. In a December 2015 order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated April 11, 2016, the MPUC approved the route permit which largely follows Minnesota Power’s preferred route, including the international border crossing, and on November 16, 2016, the U.S. Department of Energy issued a presidential permit, which was the final major regulatory approval needed before construction in the U.S. can begin in early 2017.

Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In September 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. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014.

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of net gross operating revenues from service provided in the state on energy CIPs each year. 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 3, 2016, the Minnesota Department of Commerce approved Minnesota Power’s 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 $7.3 million for 2016 ($7.1 million for 2015; $6.9 million for 2014), with actual spending of $7.4 million in 2016 ($6.6 million in 2015; $7.2 million in 2014). The investment goals for 2017, 2018 and 2019 are $10.6 million, $10.8 million and $10.9 million, respectively.

Minnesota requires each utility to establish an annual energy-savings goal of 1.5 percent of annual retail energy sales. On April 1, 2016, Minnesota Power submitted its 2015 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $7.5 million based upon MPUC procedures. In an order dated July 19, 2016, 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. The approved financial incentive will be recovered through customer billing rates in 2016 and 2017. In 2015 and 2014, the CIP financial incentives recognized were $6.2 million and $8.7 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 December 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. On September 28, 2016, the FERC issued an order affirming the administrative law judge’s recommendation.

In February 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. On June 30, 2016, a federal administrative law judge ruled on the February 2015, 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 expected in 2017. The final decision from the FERC is not expected to have a material impact on ALLETE’s Consolidated Financial Statements.

In January 2015, the FERC approved an incentive adder of up to 50 basis points on the allowed base return on equity for our participation in a regional transmission organization upon the resolution of each individual return on equity complaint.

NOTE 4. REGULATORY MATTERS (Continued)

Minnesota Solar Energy Standard. In 2013, legislation was enacted by the state of Minnesota requiring 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 20 kW or less. Minnesota Power has one completed solar project and another under development. In August 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota. In an order dated February 24, 2016, the MPUC approved the Camp Ripley solar project as eligible to meet the solar energy standard and for current cost recovery, which was subsequently finalized by the MPUC in an order dated December 12, 2016. The Camp Ripley solar project was completed in the fourth quarter of 2016. In September 2015, Minnesota Power filed for MPUC approval of a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array to be owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that will be owned and operated by Minnesota Power. In an order dated July 27, 2016, the MPUC approved the community solar garden project and cost recovery, subject to certain compliance requirements. Minnesota Power believes these projects will meet approximately one-third of the overall mandate. Additionally, on January 19, 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. This proposal to incentivize customer-sited solar installations is expected to meet a portion of the required mandate related to solar photovoltaic devices with a nameplate capacity of 20 kW or less.

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	2016		2015
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$18.6		$10.6
Total Current Regulatory Assets	18.6		10.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	226.1		219.3
Income Taxes (c)	63.3		64.2
Cost Recovery Riders (d)	30.5		58.0
Asset Retirement Obligations (e)	26.0		21.6
PPACA Income Tax Deferral	5.0		5.0
Other	8.7		3.9
Total Non-Current Regulatory Assets	359.6		372.0
Total Regulatory Assets		$378.2		$382.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$56.8		$58.0
North Dakota Investment Tax Credits (g)	28.2		12.8
Income Taxes (c)	19.1		6.1
Plant Removal Obligations	19.1		22.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	—		0.9
Other	2.6		5.1
Total Non-Current Regulatory Liabilities		$125.8		$105.0


(a)	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.

(b)

Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 15. Pension and Other Postretirement Benefit Plans.)


(c)	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. This balance will decrease over the remaining life of the related temporary differences and flow through current income taxes.

(d)

The cost recovery rider regulatory assets are revenues not yet collected from our customers primarily due to capital expenditures related to Bison, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets as of December 31, 2016, will be recovered within the next two years.


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


(f)	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.


(g)	North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers over the remaining life of Bison through future renewable cost recovery rider fillings.

Investment in ATC

12 Months Ended

Dec. 31, 2016

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 parts of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of December 31, 2016, our equity investment in ATC was $135.6 million ($124.5 million at December 31, 2015). On January 27, 2017, we invested an additional $3.1 million in ATC. In total, we expect to invest approximately $10.9 million throughout 2017.



ALLETE’s Investment in ATC
Year Ended December 31	2016			2015
Millions
Equity Investment Beginning Balance		$124.5			$121.1
Cash Investments	5.4			1.6
Equity in ATC Earnings	18.5			16.3
Distributed ATC Earnings	(12.8		)	(14.5		)
Equity Investment Ending Balance		$135.6			$124.5



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2016		2015
Millions
Current Assets		$75.8		$80.5
Non-Current Assets	4,312.9		3,957.6
Total Assets		$4,388.7		$4,038.1
Current Liabilities		$495.1		$330.3
Long-Term Debt	1,865.3		1,800.0
Other Non-Current Liabilities	271.5		245.0
Members’ Equity	1,756.8		1,662.8
Total Liabilities and Members’ Equity		$4,388.7		$4,038.1



Income Statement Data
Year Ended December 31	2016		2015		2014
Millions
Revenue		$650.8		$615.8		$635.0
Operating Expense	322.5		319.3		307.4
Other Expense	95.5		96.1		88.9
Net Income		$232.8		$200.4		$238.7
ALLETE’s Equity in Net Income		$18.5		$16.3		$19.6

On September 28, 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.

On June 30, 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 expected in 2017. (See Note 4. Regulatory Matters.) We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million after-tax.

Acquisitions

12 Months Ended

Dec. 31, 2016

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, 2016, and 2015.

2016 Activity.

Acquisition of Non-Controlling Interest. On April 15, 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. On October 11, 2016, U.S. Water Services acquired 100 percent of Water & Energy Systems Technology of Nevada, Inc. (WEST). Total consideration for the transaction was $6.5 million, subject to a cash and working capital adjustment. Consideration of $5.9 million was paid in cash on the acquisition date and a $0.6 million payment is due in April 2018. WEST, 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 Southwestern United States.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as shown in the table below. 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 working capital; 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
Cash and Cash Equivalents		$0.1
Other Current Assets	1.1
Customer Relationships (a)	2.8
Goodwill (b)	3.9
Other Non-Current Assets	0.1
Total Assets Acquired		$8.0
Liabilities Assumed
Current Liabilities		$0.2
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.4
Net Identifiable Assets Acquired		$6.6


(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 February 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.

NOTE 6. ACQUISITIONS (Continued)

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



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 April 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 97.5 MW of generating capability and are located near ALLETE Clean Energy’s Lake Benton facility. 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).

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
Power Sales Agreements	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 July 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.



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 November 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 due 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.



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.

2014 Activity.

ACE Wind Acquisition. In 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) from AES for $26.9 million.

Lake Benton, Storm Lake II and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake II began commercial operations in 1998, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032.

ALLETE Clean Energy acquired a controlling interest in the limited liability company (LLC) which owns Lake Benton and Storm Lake II, and a controlling interest in the LLC that owns Condon. 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. Fair value measurements were valued primarily using the discounted cash flow method.

NOTE 6. ACQUISITIONS (Continued)

2014 Activity (Continued)



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	14.3
Property, Plant and Equipment	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
Current Liabilities (b)		$15.2
Long-Term Debt Due Within One Year	2.2
Long-Term Debt	21.1
Power Sales Agreements	99.4
Other Non-Current Liabilities	10.6
Non-Controlling Interest (c)	7.1
Total Liabilities and Non-Controlling Interest Assumed	$155.6
Net Identifiable Assets Acquired		$26.9


(a)	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain, and goodwill of $2.9 million. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Current Liabilities included $12.4 million related to the current portion of PSAs.


(c)	The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method.

Acquisition-related costs of $1.4 million after-tax were expensed as incurred during 2014 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

In 2014, ALLETE Clean Energy purchased the non-controlling interest related to Lake Benton and Storm Lake II for $6.0 million. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income.

Storm Lake I Acquisition. In 2014, ALLETE Clean Energy acquired a wind energy facility in Storm Lake, Iowa (Storm Lake I) from NRG Energy, Inc. for $15.1 million.

Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II. The wind energy facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2019.

NOTE 6. ACQUISITIONS (Continued)

2014 Activity (Continued)



Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Current Liabilities (b)		$8.2
Power Sales Agreements	23.5
Non-Current Liabilities	17.0
Total Liabilities Assumed	$48.7
Net Identifiable Assets Acquired		$15.1


(a)	Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Current Liabilities included $7.5 million related to the current portion of PSAs.

Acquisition-related costs were immaterial, expensed as incurred during 2014 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2016

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, 2014		$2.9		—			$2.9
Acquired Goodwill (a)	0.4				$127.3	127.7
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


(a)	See Note 6. Acquisitions.

(b)

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 January 2014.

NOTE 7. GOODWILL AND INTANGIBLE ASSETS (Continued)

The following table summarizes changes to intangible assets, net, for the year ended December 31, 2016:



	December 31, 2015		Additions (a)		Amortization	December 31, 2016
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$60.8		$2.8	$(4.3)		$59.3
Developed Technology and Other (b)	7.2		—		(0.9)	6.3
Total Definite-Lived Intangible Assets	68.0		2.8		(5.2)	65.6
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$84.6		$2.8	$(5.2)		$82.2


(a)	Additions resulting from the October 11, 2016, acquisition of WEST. (See Note 6. Acquisitions.)


(b)	Developed Technology and Other includes patents, non-compete agreements and land easements.

Customer relationships have a remaining useful life of approximately 21 years, and developed technology and other have remaining useful lives ranging from approximately 2 years to approximately 12 years (weighted average of approximately 8 years). The weighted average remaining useful life of all definite-lived intangible assets as of December 31, 2016, is approximately 20 years.

Amortization expense of intangible assets for the year ended December 31, 2016, was $5.2 million ($4.0 million in 2015; $0.1 million in 2014). Accumulated amortization was $9.3 million and $4.1 million as of December 31, 2016, and December 31, 2015, respectively. Estimated amortization expense for definite-lived intangible assets is $5.5 million in 2017, $5.1 million in 2018, $4.8 million in 2019, $4.5 million in 2020, $4.4 million in 2021 and $41.3 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.

Investments

12 Months Ended

Dec. 31, 2016

Investments [Text Block]

INVESTMENTS

Investments. As of December 31, 2016, 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	2016		2015
Millions
ALLETE Properties (a)		$31.7		$50.1
Available-for-sale Securities (b)	18.8		18.5
Cash Equivalents	1.3		2.0
Other	3.8		4.0
Total Other Investments		$55.6		$74.6

(a)

On September 22, 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, with the remaining purchase price to be paid under the terms of a finance receivable due over a five-year period which bears interest at market rates. The finance receivable is collateralized by the property sold.


(b)	As of December 31, 2016, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $3.2 million, in three years to less than five years was $5.0 million, and in five or more years was $3.3 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 2016 ($36.3 million in 2015; none in 2014). (See Note 1. Operations and Significant Accounting Policies.)

NOTE 8. INVESTMENTS (Continued)

Available-for-Sale Investments. We account for our available-for-sale 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 investments were immaterial in 2016, 2015 and 2014.

Fair Value

12 Months Ended

Dec. 31, 2016

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.

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, 2016 and December 31, 2015. 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.

NOTE 9. FAIR VALUE (Continued)



	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, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.6	—		—			$7.6
Available-for-sale – Corporate Debt Securities	—			$10.9	—		10.9
Cash Equivalents	2.0		—		—		2.0
Total Fair Value of Assets		$9.6		$10.9	—			$20.5

Liabilities: (b)
Deferred Compensation	—			$16.1	—			$16.1
U.S. Water Services Contingent Consideration	—		—			$36.6	36.6
Total Fair Value of Liabilities	—			$16.1		$36.6		$52.7
Total Net Fair Value of Assets (Liabilities)		$9.6	$(5.2)		$(36.6)		$(32.2)


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


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

The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of December 31, 2016, and December 31, 2015. 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.

NOTE 9. FAIR VALUE (Continued)

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. The acquisition contingent consideration was measured at $25.0 million as of December 31, 2016.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2014	—
Recognition of U.S. Water Services Contingent Consideration		$35.7
Accretion (a)	2.4
Payments	(0.1		)
Changes in Cash Flow Projections	(1.4		)
Balance as of December 31, 2015		$36.6
Accretion (a)	2.8
Payments	(0.8		)
Changes in Cash Flow Projections	(13.6		)
Balance as of December 31, 2016		$25.0


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

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, 2016 and 2015, 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, 2016	$1,569.1	$1,653.8
December 31, 2015	$1,605.0	$1,676.0

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

Equity Method 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 $135.6 million as of December 31, 2016 ($124.5 million as of December 31, 2015). 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, 2016 and 2015, 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. Substantially all of the Company’s goodwill is a result of the U.S. Water Services acquisition in February 2015. (See Note 6. Acquisitions.) The aggregate carrying amount of goodwill was $131.2 million as of December 31, 2016 and $130.6 million as of December 31, 2015.

NOTE 9. FAIR VALUE (Continued)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Continued)

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 each reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. Our annual impairment analysis for ALLETE Clean Energy indicated the carrying amount of ALLETE Clean Energy’s goodwill may be impaired, and additional analysis was performed to measure the impact of the goodwill impairment loss. It was determined that the implied fair value of ALLETE Clean Energy’s goodwill was less than the carrying amount, resulting in an impairment charge of $3.3 million for the year ended December 31, 2016, which represented the entire carrying amount of goodwill for ALLETE Clean Energy. 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. (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 February 2015. The aggregate carrying amount of intangible assets was $82.2 million as of December 31, 2016 ($84.6 million as of December 31, 2015). 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, 2016, 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 primarily due to lower estimated energy prices in periods not under PSAs caused management to review ALLETE Clean Energy’s WTGs for impairment. Based on the results of the undiscounted cash flow analysis, the undiscounted future cash flows were adequate to recover the carrying value of the WTGs. (See Note 1. Operations and Significant Accounting Policies.) For the year ended December 31, 2016, there were no indicators of impairment.

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.

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

Short-Term and Long-Term Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2016, total short-term debt outstanding was $187.7 million ($37.3 million as of December 31, 2015), consisted of long-term debt due within one year and included $0.6 million of unamortized debt issuance costs.

As of December 31, 2016, we had bank lines of credit aggregating $409.0 million ($408.4 million as of December 31, 2015), the majority of which expire in November 2019. We had $11.1 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of December 31, 2016 ($12.4 million in standby letters of credit and $1.6 million in draws outstanding as of December 31, 2015).

Long-Term Debt. As of December 31, 2016, total long-term debt outstanding was $1,370.4 million ($1,556.7 million as of December 31, 2015) and included $10.4 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 2017 is $188.3 million; $63.1 million in 2018; $55.2 million in 2019; $101.2 million in 2020; $96.4 million in 2021; and $1,064.9 million thereafter. Substantially all of our regulated electric plant is subject to the lien of the mortgage 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 December 8, 2016, ALLETE entered into an agreement to sell $80 million of the Company's senior unsecured notes (the Notes) to certain institutional buyers in the private placement market. The Notes will be 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. The Notes will be issued on or about June 1, 2017, carry an interest rate of 3.11 percent and mature on June 1, 2027.

Interest on the Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2017. The Company has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes will be used to redeem debt, fund corporate growth opportunities and/or for general corporate purposes.

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

Long-Term Debt (Continued)



Long-Term Debt
As of December 31	2016			2015
Millions
First Mortgage Bonds
7.70% Series Due 2016	—			$20.0
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			125.0
Senior Unsecured Notes 5.99% Due 2017	50.0			50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8			27.8
Armenia Mountain Senior Secured Notes 3.26% Due 2024	74.6			83.3
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0			15.0
Other Long-Term Debt, 3.11% – 6.20% Due 2017 – 2037	61.2			68.4
Unamortized Debt Issuance Costs	(11.0		)	(12.6		)
Total Long-Term Debt	1,558.1			1,592.4
Less: Due Within One Year	187.7			35.7
Net Long-Term Debt		$1,370.4			$1,556.7

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 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, 2016, our ratio was approximately 0.45 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. As of December 31, 2016, ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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



As of December 31, 2016
Millions	2017		2018		2019		2020		2021		Thereafter
Coal, Rail and Shipping Contracts		$27.9		$27.0		$1.8	—		—		—
Leasing Agreements		$13.7		$12.0		$10.7		$7.5		$5.9		$18.3
PPAs (a)		$98.0		$102.9		$105.5		$113.4		$143.3		$1,803.9


(a)	Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only, and the 133 MW agreement with Manitoba Hydro commencing in 2020, as our obligation under this contract is subject to construction of additional transmission capacity. Also excludes Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered.

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 2017 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 delivered costs of fuel 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 terms expiring through 2023. Total lease expense was $17.1 million in 2016 ($17.3 million in 2015; $14.8 million in 2014).

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 December 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, 2016, Square Butte had total debt outstanding of $327.7 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2017 through 2021, 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 2016 was $73.3 million ($77.8 million in 2015; $70.1 million in 2014). 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 $9.6 million in 2016 ($10.1 million in 2015; $10.5 million in 2014). 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, 2016:



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
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(j)
PSA 2	100 MW	Capacity	June 2016	June 2018	Fixed
Minnkota Power	(k)	Capacity / Energy	June 2014	December 2026	(k)
Silver Bay Power	(l)	Energy	January 2017	December 2031	(m)


(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 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.

(k)

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 2016 (28 percent in 2015; 23 percent in 2014). (See Square Butte PPA.)

(l)

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 will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power will have the option to purchase additional energy from Minnesota Power as it transitions away from self-generation. On December 31, 2019, Silver Bay Power will cease its self-generation and Minnesota Power will supply the energy requirements for Silver Bay Power.


(m)	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.

The GNTL is subject to various federal and state regulatory approvals. In 2013, a certificate of need application was filed with the MPUC which was approved in a June 2015 order. Based on this order, 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 factor filings. (See Note 4. Regulatory Matters.) In a December 2015 order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated April 11, 2016, the MPUC approved the route permit which largely follows Minnesota Power’s preferred route, including the international border crossing, and on November 16, 2016, the U.S. Department of Energy issued a presidential permit, which was the final major regulatory approval needed before construction in the U.S. can begin in early 2017. Construction is expected to be completed in 2020, and total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million. Minnesota Power is expected to have majority ownership of the transmission line.

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 regulation under many of these regulations. In response to 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 to conduct such operations 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 April 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, retrofits or retirements at 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. On October 19, 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as the latest step in its EnergyForward strategic plan. We believe that costs to retire 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 a total of 28 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 that 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.

In 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017 and beyond) for 2017 and 2018 were distributed on June 29, 2016. Based on our review of the NO_x and SO₂ Phase I and Phase II allowances already issued, and Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will result in compliance in both Phase I and Phase II.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) 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 EPA published the final MATS rule in the Federal Register in 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs and work practice standards for the remaining categories. Affected sources were required to be in compliance with the rule by April 2015. States had the authority to grant sources a one-year extension. The MPCA approved Minnesota Power’s request for an extension of the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed in 2015. Boswell Unit 3 is also subject to the MATS rule; however, investments and compliance work completed at Boswell Unit 3, including the emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to natural gas in June 2015 positioned those units for MATS compliance.

In June 2015, the U.S. Supreme Court reversed and remanded an earlier U.S. Court of Appeals for the D.C. Circuit decision on the MATS rule. The U.S. Supreme Court ruled that it was unreasonable for the EPA to deem cost of compliance irrelevant in determining that regulation of emissions of hazardous air pollutants from power plants was “appropriate and necessary” under Section 112 of the Clean Air Act. The MATS rule remains in effect until the U.S. Court of Appeals for the D.C. Circuit acts on the remand. In December 2015, the U.S. Court of Appeals for the D.C. Circuit rejected a motion by utilities and states to vacate the MATS rule, instead ordering the rule to remain in effect while the EPA completes its review. On April 15, 2016, the EPA announced its determination that the MATS rule is appropriate and necessary, even after considering cost of compliance. The outcome of these proceedings is not expected to have a material impact on Minnesota Power generation due to emission reduction obligations under the Minnesota Mercury Emissions Reduction Act and the Consent Decree. (See New Source Review.)

Minnesota Mercury Emissions Reduction Act/Rule. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, which was incorporated into rules promulgated by the MPCA in September 2014, 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler MACT became effective in 2012. Major existing sources had until January 31, 2016, to achieve compliance with the final rule and July 29, 2016, to perform initial compliance demonstrations. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule and are currently in compliance. Compliance consists largely of adjustments to our operating practices; therefore, the costs for complying with the final rule are not expected to be material.

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. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA has proposed more stringent control related to emissions that result in ground level ozone. In 2010, the EPA proposed to revise the 2008 eight-hour ozone standard of 75 parts per billion (ppb) and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. In October 2015, the EPA published the final rule in the Federal Register revising the eight-hour ozone standard to 70 ppb with a secondary standard also set at 70 ppb. 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 ozone continue in the state. No additional costs for compliance are anticipated at this time.

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM_2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. In 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5 standard, while retaining the current 24-hour PM_2.5 standard. To implement the new annual PM_2.5 standard, the EPA is revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by 2013, based on already available monitoring data, and issued designations of the 2012 revised primary annual fine particulate attainment status in 2014. The EPA 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. On September 27, 2016, environmental groups filed a lawsuit against the EPA in the United States District Court for the Northern District of California alleging the EPA had failed to fully implement the PM_2.5standards in 24 states, including Minnesota, by not enforcing states’ submittals of required infrastructure SIPs 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.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO₂ and NO₂. Ambient monitoring data indicates that Minnesota is likely in compliance with these standards; however, the one-hour SO₂ NAAQS also requires the EPA to evaluate additional modeling and monitoring considerations to determine attainment. In 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by 2013. However, the State of Minnesota delayed completing the documents pending EPA guidance to states for preparing the SIP submittal.

In 2013, the EPA provided guidance to states regarding implementation of the one-hour NO₂ NAAQS and in 2014, as clarified in February 2015, the MPCA submitted a SIP revision to the EPA addressing the infrastructure requirements of Sections 110(a)(1) and 110(a)(2) of the Clean Air Act in regards to the one-hour NO₂ and SO₂ NAAQS, among other standards. The SIP stated that since the EPA determined in 2012 that no area in the country is in violation of the one-hour NO₂ NAAQS, there are no nonattainment areas in the country for this pollutant, and therefore Minnesota’s NO₂ emissions cannot be significantly contributing to nonattainment in any other state. In October 2015, the EPA published in the Federal Register an approval and partial disapproval of the 2014 SIP revision. According to the MPCA, the partial disapproval is regarding state delegation of a program unrelated to the one-hour NAAQS for SO₂ and NO_2,and is not expected to require further action. As such, additional compliance costs for the one-hour NO₂ NAAQS are not expected at this time.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In August 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 rule sets emissions thresholds and exemptions for facilities that trigger modeling requirements. On January 8, 2016, the MPCA informed the EPA of the Minnesota sources subject to the rule, confirming that Boswell and Taconite Harbor are the only Minnesota Power generating facilities subject to the DRR. The MPCA was required to notify the EPA as to how each source will evaluate air quality by July 1, 2016. Compliance options include ambient monitoring, modeling existing enforceable emission limits, or modeling actual emissions. The MPCA initially informed Minnesota Power that compliant SO₂ modeling recently completed at these facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also requires 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 on September 1, 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. Compliance costs for the one-hour SO₂ NAAQS are not expected to be material.

Class I Air Quality Petitions and Requests. In 2014, the Fond du Lac Band of Lake Superior Chippewa (Fond du Lac Band) announced its intent to petition the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Fond du Lac Band does not currently possess authority to directly regulate air quality. Class I air shed status, if granted, would allow the Fond du Lac Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have received Class I status. A public hearing was held by the Fond du Lac Band in October 2014, and the extended public comment period on the petition expired in November 2014. After the Fond du Lac Band prepares responses to the comments, it is anticipated to make a formal submittal request to the EPA.

In 2013, the Bad River Band of Lake Superior Chippewa (Bad River Band) announced its intent to petition the EPA to redesignate its reservation air shed, which is located approximately 100 miles east of Duluth, Minnesota, from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Class I analysis report was issued by the Bad River Band in January 2015 which was followed by public hearings in March 2015 and a public comment period ending in May 2015. After the Bad River Band prepares responses to the comments, it is also anticipated to make a formal submittal request to the EPA.

There is no deadline for the approval, denial, or modification of these requests by the EPA. We are unable to determine the impact of potential Class I status on the Company’s operations at this time.

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 energy supply;


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


•	Improving efficiency of our energy generating facilities;


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


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

President Obama’s Climate Action Plan. In 2015, President Obama announced an updated Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions.

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 are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific, top‑down Best Available Control Technology (BACT) determination process used for other pollutants will also be used to determine BACT for GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of GHG emission control technologies and techniques the EPA considers available or likely to be available to sources. It is possible that these control technologies could be determined to be BACT on a project-by-project basis.

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 power to require 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. At this time, we are unable to predict the compliance costs that we might incur.

On October 3, 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 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS), under Section 111(b) of the Clean Air Act, to new fossil fuel-fired electric generating units. The proposed NSPS would have applied only to new or re-powered units. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. In 2013, the EPA retracted its 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO₂ emissions.

In 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in August 2015, together with a proposed federal implementation plan and a model rule for emissions trading. Petitions for review of the rule were filed with the U.S. Court of Appeals for the District of Columbia Circuit. On February 9, 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. On September 27, 2016, the U.S. Court of Appeals for the District of Columbia heard oral arguments and is currently deliberating. 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.

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 maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constitutes the EPA’s guideline for a Best System of Emission Reductions (BSER). BSER is comprised of three building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, and 3) building more zero- and low-emitting power sources, including renewable energy. States may also choose to include avoided CO₂ emissions from customer energy efficiency measures for credit towards meeting state goals.

State goals under the CPP are expressed as both mass-based and rate-based, and include interim goals to be met over the years 2022 through 2029, as well as a final goal to be met in 2030 and thereafter. Under the original schedule for the CPP, each state would have been required to develop a SIP by September 6, 2016, or by September 6, 2018, if granted an extension. Due to the U.S. Supreme Court order staying the effectiveness of the CPP, those SIP submittal dates are not currently in effect. If the CPP is upheld at the completion of the appellate court process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In developing its plan, a state may choose to meet either the mass-based or the rate-based goals. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota as well as its potential impact on the Company and is actively discussing potential compliance scenarios with regulatory agencies and in public stakeholder meetings. Minnesota has already initiated several measures consistent with those called for under the CAP and 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.)

The EPA accepted comments through November 1, 2016, on the proposed Clean Energy Incentive Program (CEIP) that may be facilitated as part of the CPP. The CEIP would reassign CPP emission rate credits or allowances for certain early action or designated deployments of renewable energy and energy efficiency measures.

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 any additional costs through a rate proceeding.

Minnesota’s Next Generation Energy Act of 2007. In April 2014, the U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 (NEGA) violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO₂-producing facility outside of Minnesota and prohibited the entry into new long-term PPAs that would increase CO₂ emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit in 2014. On June 15, 2016, the U.S. Court of Appeals for the Eighth Circuit upheld the federal district court’s decision that part of the NEGA violated the Commerce Clause of the U.S. Constitution. Minnesota Governor Dayton subsequently announced that the State of Minnesota would cease pursuing further appeals of the U.S. Court of Appeals for the Eighth Circuit’s decision.

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

Clean Water Act - Aquatic Organisms. In 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would 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 was effective in 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDES permits for Minnesota Power generating facilities have been re-issued containing Section 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment suggests costs of compliance up to $15 million over the next 5 years. Minnesota Power would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In 2013, the EPA announced proposed revisions to the federal effluent limit guidelines (ELG) for steam electric power generating stations under the Clean Water Act. The final ELG was issued in September 2015. It sets effluent limits and prescribes BACT for several wastewater streams, including flue gas desulphurization (FGD) water and coal combustion landfill leachate. The ELG rule also prohibits the discharge of bottom and fly ash contact waters. Compliance with the final rule is required between November 1, 2018, and December 31, 2023.

We are reviewing the final rule and evaluating its potential impact on Minnesota Power’s operations, 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 currently discharge, but may do so in the future. Under the final ELG rule, bottom ash discharge would not be allowed and bottom ash contact water would either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system would need to be converted to a dry process. If the FGD wastewater is discharged in the future, it would require additional wastewater treatment. 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. Additional efforts are underway to determine if land application of certain wastewater streams under a state disposal system may be feasible.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

Coal Ash Management Facilities. Minnesota Power generates or disposes coal ash at four of its electric generating facilities. One facility stores ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility’s ash is beneficially re-used. The other two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. In 2010, the EPA proposed regulations for coal combustion residuals (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).

The EPA issued the final CCR rule in 2014 under Subtitle D (non-hazardous) of RCRA and it was published in the Federal Register in April 2015. 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. Recently, the EPA has indicated to Minnesota Power that the Taconite Harbor landfill is a CCR unit, based on 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. Compliance costs, if any for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of any additional costs through a general rate case.

Other Environmental Matters. On November 28, 2016, U.S. Water Services received notice from the EPA regarding potential violations under the Federal Insecticide, Fungicide and Rodenticide Act for the sale of certain chemicals without registration or that were misbranded. The potential violations primarily relate to sales in 2013 by a U.S. Water Services subsidiary acquired in 2013. U.S. Water Services is cooperating with the EPA in its investigation of these potential violations. We are unable to predict the outcome of this matter at this time, but we do not expect that any potential fines will have a material effect on our financial position, results of operations or cash flows.

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, 2016, ALLETE Clean Energy has $14.6 million outstanding in standby letters of credit.

U.S. Water Services. As of December 31, 2016, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of December 31, 2016, BNI Energy had surety bonds outstanding of $49.9 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. In addition to the surety bonds, BNI Energy has secured a letter of credit for an additional $0.6 million to provide for BNI Energy’s total reclamation liability, which 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, 2016, ALLETE Properties, through its subsidiaries, 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 approximately $5.4 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 we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. As of December 31, 2016, we owned 72 percent of the assessable land in the Town Center District (72 percent as of December 31, 2015) and 92 percent of the assessable land in the Palm Coast Park District (92 percent as of December 31, 2015). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are approximately $1.4 million for the Town Center District and $2.1 million for the Palm Coast Park District. 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 the 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, 2016

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, 2013	41,401			$885.2
Employee Stock Purchase Program	18		0.8
Invest Direct	378		18.9
Options and Stock Awards	78		8.0
Equity Issuance Program	1,851		90.0
Forward Sale Agreement and Issuance	1,807		85.2
Contributions to Pension	396		19.5
Balance as of December 31, 2014	45,929		1,107.6
Employee Stock Purchase Program	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 Program	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

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 3.9 million shares remain available for issuance. For the year ended December 31, 2016, 0.1 million shares of common stock were issued under this agreement, resulting in net proceeds of $8.0 million (1.3 million shares for net proceeds of $69.9 million in 2015; 1.9 million shares for net proceeds of $90.0 million in 2014). The shares issued in 2015 and 2014, were offered and sold pursuant to Registration Statement No. 333-190335. On August 1, 2016, we filed Registration Statement No. 333-212794, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

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). In accordance with accounting standards for earnings per share, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share in 2016, 2015 and 2014.

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.

In connection with the public offering of the 2.8 million shares, ALLETE granted the underwriters an option to purchase up to an additional 0.4 million shares of ALLETE common stock (the option shares). The underwriters exercised the option in full and in March 2014, the Company issued and sold the option shares to the underwriters at a price to ALLETE equal to the initial forward sale price for proceeds of $20.2 million.

Contributions to Pension. On January 17, 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. No shares of ALLETE common stock were contributed to the pension plan for the years ended December 31, 2016 and 2015. In 2014, we contributed approximately 0.4 million shares of ALLETE common stock to our pension plan, which had an aggregate value of $19.5 million when contributed. 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.

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



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
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
2014
Net Income Attributable to ALLETE		$124.8			$124.8
Average Common Shares	42.9		0.2	43.1
Earnings Per Share		$2.91			$2.90

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Income Tax Expense [Text Block]

Income Tax Expense

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2016			2015			2014
Millions
Current Tax Expense (a)
Federal	—			—			$1.1
State	$0.4			$0.2			2.9
Total Current Tax Expense		$0.4			$0.2			$4.0
Deferred Tax Expense
Federal		$12.0			$19.4			$25.3
State	8.1			6.5			8.2
Investment Tax Credit Amortization	(0.7		)	(0.8		)	(0.8		)
Total Deferred Tax Expense		$19.4			$25.1			$32.7
Total Income Tax Expense		$19.8			$25.3			$36.7

(a)

For the years ended December 31, 2016, 2015 and 2014, 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. The year ended December 31, 2014, includes the resolution of an Internal Revenue Service examination for tax years 2005 through 2009 and the impacts of initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired.

NOTE 13. INCOME TAX EXPENSE (Continued)



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2016			2015			2014
Millions
Income Before Non-Controlling Interest and Income Taxes		$175.6			$166.8			$162.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$61.5			$58.4			$56.8
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	5.6			4.4			7.2
Regulatory Differences for Utility Plant	(0.1		)	(0.6		)	(3.5		)
Production Tax Credits	(41.5		)	(37.0		)	(23.7		)
Change in Fair Value of Contingent Consideration	(3.8		)	—			—
Other	(1.9		)	0.1			(0.1		)
Total Income Tax Expense		$19.8			$25.3			$36.7

The effective tax rate was 11.3 percent for 2016 (15.2 percent for 2015; 22.6 percent for 2014). The 2016, 2015, and 2014 effective rates were primarily impacted by production tax credits. The 2016 effective rate was also impacted by a decrease in the liability related to U.S. Water Services’ contingent consideration (see Note 9. Fair Value), and the 2014 effective rate was also impacted by the deduction for AFUDC–Equity (included in Regulatory Differences for Utility Plant in the preceding table).



Deferred Tax Assets and Liabilities
As of December 31	2016			2015
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$104.6			$105.4
Property Related	117.8			126.6
NOL Carryforwards	185.6			186.4
Tax Credit Carryforwards	227.4			164.8
Power Sales Agreements	59.3			73.0
Other	46.9			21.8
Gross Deferred Tax Assets	741.6			678.0
Deferred Tax Asset Valuation Allowance	(43.0		)	(31.6		)
Total Deferred Tax Assets		$698.6			$646.4
Deferred Tax Liabilities
Property Related		$1,094.7			$1,053.0
Regulatory Asset for Benefit Obligations	91.9			89.4
Unamortized Investment Tax Credits	33.3			26.0
Partnership Basis Differences	50.9			47.8
Other	11.9			10.0
Total Deferred Tax Liabilities		$1,282.7			$1,226.2
Net Deferred Income Taxes (a)		$584.1			$579.8


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

NOTE 13. INCOME TAX EXPENSE (Continued)



NOL and Tax Credit Carryforwards
As of December 31	2016	2015
Millions
Federal NOL Carryforwards (a)	$485.3		$493.0
Federal Tax Credit Carryforwards	$163.7	$113.6
State NOL Carryforwards (a)	$294.4	$228.6
State Tax Credit Carryforwards (b)	$21.0	$20.0


(a)	Pre-tax amounts.


(b)	Net of a $42.7 million valuation allowance as of December 31, 2016 ($31.2 million as of December 31, 2015).

The federal NOL and tax credit carryforward periods expire between 2030 and 2036. 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, 2016. The state NOL and tax credit carryforward periods expire between 2024 and 2045. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.



Gross Unrecognized Income Tax Benefits	2016			2015			2014
Millions
Balance at January 1		$2.4			$2.0			$1.2
Additions for Tax Positions Related to the Current Year	0.1			0.5			—
Additions for Tax Positions Related to Prior Years	0.2			0.7			1.0
Reductions for Tax Positions Related to Prior Years	(0.3		)	(0.7		)	—
Lapse of Statute	(0.4		)	(0.1		)	(0.2		)
Balance as of December 31		$2.0			$2.4			$2.0

Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The gross unrecognized tax benefits as of December 31, 2016, included $0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.

As of December 31, 2016, we had no accrued interest (none as of December 31, 2015; none as of December 31, 2014) 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 2016 (immaterial in 2015, and in 2014). There were no penalties recognized in 2016, 2015 or 2014. 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, 2016

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.

Changes in accumulated other comprehensive loss, net of tax, for the years ended December 31, 2016, 2015 and 2014, 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, 2013	$(0.1)		$(16.7)		$(0.3)		$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.3	)	(5.2	)	0.2		(5.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	0.1		1.2		—		1.3
Net Other Comprehensive Income (Loss)	(0.2	)	(4.0	)	0.2		(4.0	)
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)


(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.)

The entire disclosure for any adjustments made during the period to avoid double counting in comprehensive income items displayed as part of net income that also had been displayed as part of other comprehensive income in that period or earlier periods. These adjustments include reclassifications to net income of items in accumulated comprehensive income, such as deferred gains or losses on qualifying hedges when hedged item reported in net income, holding gains or losses on available-for-sale securities transferred into trading category, unrealized holding gains or losses on debt securities transferred from held-to-maturity category into available-for-sale category and accumulated translation adjustment attributable to foreign subsidiary or investment in foreign entity upon sale or liquidation.

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2016

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 on January 1, 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 $6.3 million in cash to the plans in 2016 (none in 2015; $19.5 million of ALLETE common stock in 2014). On January 13, 2017, we contributed $1.7 million in cash to the plans, and on January 17, 2017, we contributed $13.5 million of ALLETE common stock to the plans. We also have a defined contribution RSOP covering substantially all employees. The 2016 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $9.2 million ($9.0 million for the 2015 plan year; $9.1 million for the 2014 plan year). (See Note 12. Common Stock and Earnings Per Share and Note 16. Employee Stock and Incentive Plans.)

In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

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 2016, no contributions were made to the VEBAs (none in 2015; none in 2014) and no contributions were made to the grantor trusts (none in 2015; none in 2014).

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. We expect no additional contributions to the defined benefit pension plans in 2017 beyond the $15.2 million contributed in January 2017. We expect no contributions to the defined benefit postretirement health and life plans in 2017.

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	2016			2015
Millions
Accumulated Benefit Obligation		$698.8			$665.0
Change in Benefit Obligation
Obligation, Beginning of Year		$709.8			$714.5
Service Cost	8.1			10.1
Interest Cost	33.2			29.9
Actuarial (Gain) Loss	12.4			(31.2		)
Benefits Paid	(44.5		)	(40.2		)
Participant Contributions	24.3			26.7
Obligation, End of Year		$743.3			$709.8
Change in Plan Assets
Fair Value, Beginning of Year		$521.3			$544.2
Actual Return on Plan Assets	48.8			(10.8		)
Employer Contribution (a)	31.9			28.1
Benefits Paid	(44.5		)	(40.2		)
Fair Value, End of Year		$557.5			$521.3
Funded Status, End of Year	$(185.8)			$(188.5)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.4)			$(1.3)
Non-Current Liabilities	$(184.4)			$(187.2)


(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 $250.4 million as of December 31, 2016 (net loss of $252.7 million as of December 31, 2015).



Components of Net Periodic Pension Expense
Year Ended December 31	2016			2015			2014
Millions
Service Cost		$8.1			$10.1			$8.3
Interest Cost	33.2			29.9			29.8
Expected Return on Plan Assets	(43.6		)	(40.7		)	(38.2		)
Amortization of Loss	9.5			17.9			14.2
Amortization of Prior Service Cost	—			0.2			0.3
Net Pension Expense		$7.2			$17.4			$14.4



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2016		2015
Millions
Net Loss	$7.2			$20.2
Amortization of Prior Service Cost	—		(0.2		)
Amortization of Loss	(9.5	)	(17.9		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(2.3)			$2.1



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2016		2015
Millions
Projected Benefit Obligation		$743.3		$709.8
Accumulated Benefit Obligation		$698.8		$665.0
Fair Value of Plan Assets		$557.5		$521.3

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



Postretirement Health and Life Obligation and Funded Status
As of December 31	2016			2015
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$160.2			$170.9
Service Cost	3.9			4.3
Interest Cost	7.4			7.2
Actuarial (Gain) Loss	11.9			(14.4		)
Benefits Paid	(13.1		)	(10.7		)
Participant Contributions	3.1			2.9
Obligation, End of Year		$173.4			$160.2
Change in Plan Assets
Fair Value, Beginning of Year		$153.4			$163.2
Actual Return on Plan Assets	9.6			(3.5		)
Employer Contribution	1.3			1.5
Participant Contributions	3.1			2.9
Benefits Paid	(13.1		)	(10.7		)
Fair Value, End of Year		$154.3			$153.4
Funded Status, End of Year	$(19.1)			$(6.8)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$1.4			$6.4
Current Liabilities	$(1.1)			$(1.0)
Non-Current Liabilities	$(19.4)			$(12.2)

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $17.6 million in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of December 31, 2016 ($17.4 million as of December 31, 2015).

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	2016		2015
Millions
Net Loss	$19.8		$6.5
Prior Service Credit	(4.7	)	(7.6	)
Total Unrecognized Postretirement Health and Life Cost (Credit)	$15.1		$(1.1)



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2016			2015			2014
Millions
Service Cost		$3.9			$4.3			$3.4
Interest Cost	7.4			7.2			7.3
Expected Return on Plan Assets	(11.2		)	(10.9		)	(10.3		)
Amortization of Loss	0.2			0.4			0.5
Amortization of Prior Service Credit	(2.9		)	(3.0		)	(2.5		)
Net Postretirement Health and Life Credit	$(2.6)			$(2.0)			$(1.6)

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



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2016			2015
Millions
Net Loss		$13.5		—
Amortization of Prior Service Credit	2.9				$3.0
Amortization of Loss	(0.2		)	(0.4		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$16.2			$2.6



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2017		$45.0		$9.3
2018		$45.2		$9.4
2019		$45.4		$9.7
2020		$45.5		$9.9
2021		$45.8		$10.0
Years 2022 – 2026		$231.0		$51.4

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, 2017, are as follows:



	Pension	Postretirement Health and Life
Millions
Net Loss	$9.9	$0.3
Prior Service Credit	—	(2.0)
Total Pension and Postretirement Health and Life Cost (Credit)	$9.9	$(1.7)



Assumptions Used to Determine Benefit Obligation
As of December 31	2016	2015
Discount Rate
Pension	4.53%	4.72%
Postretirement Health and Life	4.57%	4.73%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	5.00 - 7.00%	6.50%
Ultimate Trend Rate	4.50%	5.00%
Year Ultimate Trend Rate Effective	2038	2022

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



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2016	2015	2014
Discount Rate	4.72 - 4.73%	4.30 - 4.33%	4.93 - 4.96%
Expected Long-Term Return on Plan Assets (a)
Pension	8.00%	8.00%	8.00%
Postretirement Health and Life	6.40 - 8.00%	6.40 - 8.00%	6.40 - 8.00%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%	3.70 - 4.30%


(a)	The expected long-term rates of return used to determine net periodic benefit expense for 2017 have been reduced to 7.50 percent for pension expense and 6.00 percent to 7.50 percent for postretirement health and life expense.

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

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

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. In 2014, revised mortality tables were released, and the Company adopted updated mortality tables as of December 31, 2014.



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		$20.1	$(16.7)
Effect on Postretirement Health and Life Obligation		$1.8	$(1.4)



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2016		2015		2016		2015
Equity Securities	49	%	47	%	60	%	57	%
Debt Securities	39	%	39	%	34	%	35	%
Private Equity	7	%	8	%	6	%	8	%
Real Estate	5	%	6	%	—		—
	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, 2016 (no shares as of December 31, 2015). On January 17, 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.

In 2013, the defined benefit pension plan 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 continue to be 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.

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

Following are the current targeted allocations as of December 31, 2016:



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, 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

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

Pension Fair Value (Continued)



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$33.9		$42.1	—			$76.0
U.S. Mid-cap Growth (a)	14.2		17.7		—		31.9
U.S. Small-cap (a)	14.5		17.9		—		32.4
Mutual Funds	8.4		—		—		8.4
International	44.7		42.0		—		86.7
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		185.3		—		188.0
Cash and Cash Equivalents	25.6		—		—		25.6
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$144.1		$305.0		$72.2		$521.3

(a)

The underlying investments classified under U.S. Equity Securities consist of money market 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 Large-cap, 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, 2014		$43.3			$28.9
Actual Return on Plan Assets	2.6			2.9
Purchases, Sales, and Settlements – Net	(2.6		)	(2.9		)
Balance as of December 31, 2015		$43.3			$28.9

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

Postretirement Health and Life Fair Value



	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)		$27.9	—		—			$27.9
U.S. Mid-cap Growth (a)	20.7		—		—		20.7
U.S. Small-cap (a)	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 classified under U.S. Equity Securities 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



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$28.2	—		—			$28.2
U.S. Mid-cap Growth (a)	19.1		—		—		19.1
U.S. Small-cap (a)	12.1		—		—		12.1
International	26.8		—		—		26.8
Debt Securities:
Mutual Funds	45.2		—		—		45.2
Fixed Income	—			$8.4	—		8.4
Cash and Cash Equivalents	1.6		—		—		1.6
Private Equity Funds	—		—			$12.0	12.0
Total Fair Value of Assets		$133.0		$8.4		$12.0		$153.4


(a)	The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

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

Postretirement Health and Life Fair Value (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2014		$12.9
Actual Return on Plan Assets	1.2
Purchases, Sales, and Settlements – Net	(2.1		)
Balance as of December 31, 2015		$12.0

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, 2016

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 (term not to exceed 25 years at 10.25 percent) to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our common stock. The note was refinanced in 2006 at 6 percent and subsequently 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. With the maturity of the note, 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 $9.2 million in 2016 ($9.0 million in 2015; $9.1 million in 2014).

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	2016	2015	2014
Millions
ESOP Shares
Allocated	1.6	1.8	1.9
Unallocated	—	—	0.3
Total	1.6	1.8	2.2
Fair Value of Unallocated Shares	—	—		$13.2

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 common stock reserved for issuance under the Executive Plan, with 0.8 million of these shares available for issuance as of December 31, 2016.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock Based Compensation (Continued)

We currently have the following types of share-based awards outstanding:

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.

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.

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	2016		2015		2014
Millions
Performance Shares		$1.8		$1.8		$1.6
Restricted Stock Units	0.8		0.8		0.7
Total Share-Based Compensation Expense		$2.6		$2.6		$2.3
Income Tax Benefit		$1.1		$1.1		$1.0

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock Based Compensation (Continued)

There were no capitalized share-based compensation costs during the years ended December 31, 2016, 2015 or 2014.

As of December 31, 2016, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $2.3 million and $1.0 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and 1.6 years for restricted stock units.

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



	2016				2015				2014
	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	39,654			$44.39	66,279			$44.39	108,299			$44.10
Granted (a)	—		—		—		—		—		—
Exercised	(35,297	)		$44.89	(24,456	)		$44.52	(42,020	)		$43.65
Forfeited	—		—		(2,169	)	$42.93		—		—
Outstanding as of December 31	4,357			$40.29	39,654			$44.39	66,279			$44.39
Exercisable as of December 31	4,357			$40.29	39,654			$44.39	66,279			$44.39


(a)	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Cash received from non-qualified stock options exercised was $1.6 million in 2016. 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 $0.5 million during 2016 ($0.2 million in 2015; $0.4 million in 2014).



	Exercise Price
As of December 31, 2016	$39.10		$48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	3,816		541
Weighted Average Remaining Contractual Life (Years)	1.1		0.1
Weighted Average Exercise Price		$39.10		$48.65
Aggregate Intrinsic Value (Millions)		$0.1	—

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



	2016				2015				2014
	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	119,540			$52.72	119,635			$48.26	114,765			$47.02
Granted (a)	57,189			$52.43	43,583			$58.95	47,992			$46.47
Awarded	—		—		—		—		(36,515	)		$42.01
Unearned Grant Award	(42,126	)		$52.70	(36,670	)		$45.41	—		—
Forfeited	(7,023	)		$53.45	(7,008	)		$53.49	(6,607	)		$48.29
Non-vested as of December 31	127,580			$52.56	119,540			$52.72	119,635			$48.26

(a) Shares granted include accrued dividends.

NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

Stock Based Compensation (Continued)

There were 41,755 performance shares granted in January 2017 for the three-year performance period ending in 2019. 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 $2.6 million. There were no performance shares awarded in February 2017 for the three-year performance period ending in 2016.

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



	2016				2015				2014
	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	57,694			$49.86	53,888			$44.47	55,982			$40.85
Granted (a)	20,351			$50.25	26,702			$54.81	19,645			$48.44
Awarded	(19,661	)		$44.33	(19,464	)		$41.44	(18,860	)		$37.64
Forfeited	(3,656	)		$52.87	(3,432	)		$51.52	(2,879	)		$45.92
Available as of December 31	54,728			$51.79	57,694			$49.86	53,888			$44.47

(a) Shares granted include accrued dividends.

There were 17,639 restricted stock units granted in January 2017 for the vesting period ending in 2019. The grant date fair value of the restricted stock units granted was $1.1 million. There were 14,794 restricted stock units awarded in February 2017. The grant date fair value of the shares awarded was $0.7 million.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Business Segments [Text Block]

Business Segments

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

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, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. 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 which was acquired in February 2015. 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	2016			2015			2014
Millions
Operating Revenue
Regulated Operations		$1,000.7			$991.2			$1,003.5

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	80.5			262.1			33.2
U.S. Water Services	137.5			119.8			—

Corporate and Other	121.0			113.3			100.1
Total Operating Revenue		$1,339.7			$1,486.4			$1,136.8
Net Income (Loss) Attributable to ALLETE
Regulated Operations (b)		$135.5			$131.6			$123.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	13.4			29.9			3.3
U.S. Water Services	1.5			0.9			—

Corporate and Other (b)	4.9			(21.3		)	(1.5		)
Total Net Income Attributable to ALLETE		$155.3			$141.1			$124.8
Depreciation and Amortization
Regulated Operations		$154.3			$135.1			$118.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	22.3			18.7			10.1
U.S. Water Services	8.9			7.3			—

Corporate and Other	10.3			8.9			7.6
Total Depreciation and Amortization		$195.8			$170.0			$135.7
Operating Expenses – Other (c)
ALLETE Clean Energy	$3.3			—			—
Corporate and Other	(13.6		)	$36.3			—
Total Operating Expenses – Other	$(10.3)			$36.3			—
Interest Expense
Regulated Operations (b)	$52.1			$53.9			$49.2

Energy Infrastructure and Related Services
ALLETE Clean Energy	5.8			3.3			0.8
U.S. Water Services	1.7			1.4			—

Corporate and Other (b)	14.5			8.6			7.1

Eliminations (b)	(3.8		)	(2.3		)	(2.3		)
Total Interest Expense	$70.3			$64.9			$54.8
Equity Earnings in ATC
Regulated Operations	$18.5			$16.3			$19.6


(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)	During 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries. The amounts are eliminated in consolidation.


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

NOTE 17. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2016		2015			2014
Millions
Income Tax Expense (Benefit)
Regulated Operations		$5.9		$24.4			$39.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	8.1		21.0			2.3
U.S. Water Services	1.4		0.9			—

Corporate and Other	4.4		(21.0		)	(4.6		)
Total Income Tax Expense		$19.8		$25.3			$36.7



As of December 31	2016		2015
Millions
Assets
Regulated Operations (a)	$3,853.4		$3,853.1

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	566.0		501.5
U.S. Water Services	264.1		258.3

Corporate and Other	222.9		281.6
Total Assets (a)		$4,906.4		$4,894.5
Capital Expenditures
Regulated Operations	$121.8		$224.4

Energy Infrastructure and Related Services
ALLETE Clean Energy	106.9		8.6
U.S. Water Services	3.7		2.9

Corporate and Other	15.4		15.9
Total Capital Expenditures		$247.8		$251.8


(a)	As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been reclassified to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

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
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, 2016

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
2014 Trade Accounts Receivable		$1.1		$1.8	—		$1.8		$1.1
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
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	—
Deferred Asset Valuation Allowance
2014 Deferred Tax Assets		$8.0	$14.1		—	—			$22.1
2015 Deferred Tax Assets		$22.1	$9.5		—	—			$31.6
2016 Deferred Tax Assets		$31.6		$11.4	—	—			$43.0


(a)	Includes uncollectible accounts written-off.

Operations and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 problems 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 the share price trends and the impact of overall market conditions. (See Note 8. Investments.) We account for our available-for-sale 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 market. 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 are carried at an average cost, first-in, first-out or specific identification basis. Fuel for generation is carried at an average cost basis. Certain other inventories, including capital spares, are carried at specific cost.
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 non-utility property, plant and equipment are recognized when they are retired or otherwise disposed. When utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for component depreciation. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 2. Property, Plant and Equipment.) We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.
Impairment of Long-Lived Assets [Policy Text Block]	We review our long-lived assets, which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. Land inventory is accounted for as held for use and is recorded at cost or 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. 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. 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 of the date of our annual goodwill impairment testing in 2016, the ALLETE Clean Energy and U.S. Water Services reporting units 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 compare 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 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 each 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 and trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents and non-compete agreements, which are amortized on a straight-line basis with estimated remaining useful lives ranging from approximately 2 years to approximately 21 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 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]	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. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved. 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 service 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. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is billed to customers pursuant to the fuel adjustment clause. Revenue from cost recovery riders (transmission, renewable and environmental improvement) is accounted for in accordance with the accounting standards 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 commission, 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 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 and net purchases in Fuel and Purchased Power 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 wind energy facilities acquisitions in 2014 and 2015, ALLETE Clean Energy 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.
Revenue from Cost Recovery Riders [Policy Text Block]	Revenue from cost recovery riders (transmission, renewable and environmental improvement) is accounted for in accordance with the accounting standards 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 commission, 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 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]	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 the accounting standards 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. Prior to the November 30, 2016, MPUC order, Minnesota Power accounted for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. 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 had 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 were included in the ALLETE consolidated group.
Unrecognized Tax Benefits [Policy Text Block]	In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 percent likely. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet. Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
Excise Taxes [Policy Text Block]	We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.
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 preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as shown in the table below. 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 working capital; 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. 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. 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.
New Accounting Standards [Policy Text Block]	Revenue from Contracts with Customers. In May 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict 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. The Company is considering the impact of the new guidance on its ability to recognize revenue from certain contracts where collectibility is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). The guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018. Amendments to the Consolidation Analysis. In February 2015, the FASB issued revised guidance which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The new standard affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our Consolidated Financial Statements. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) New Accounting Standards (Continued) Presentation of Debt Issuance Costs. In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented on the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability. This guidance was adopted in the first quarter of 2016 resulting in the reclassification of unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. The effect of the adoption decreased Total Assets and Total Liabilities on the Consolidated Balance Sheet by $12.6 million as of December 31, 2015. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). In May 2015, the FASB issued an accounting standard update which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share (or its equivalent) practical expedient. The guidance applies to investments for which there is not a readily determinable fair value (market quote) or the investment is in a mutual fund without a publicly available net asset value. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our Consolidated Financial Statements. Simplifying the Measurement of Inventory. In July 2015, the FASB issued an accounting standard 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 is effective for the Company beginning in the first quarter of 2017; early adoption is permitted. The adoption of this update is not expected to have a material impact on our Consolidated Financial Statements. 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 updated guidance. The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. The Company is evaluating the impact of the amended lease guidance on the Company’s 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 is effective for the Company beginning 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. 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. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018, and the guidance will result in changes to the Company’s Consolidated Statement of Cash Flows relating to debt prepayments, contingent consideration payments, proceeds from insurance settlements, proceeds from corporate-owned life insurance policies and distributions received from equity method investees. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) New Accounting Standards (Continued) 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. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018, and 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. Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued an accounting standard update to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. The guidance requires a goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The accounting guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis. The Company is evaluating the impact of the amended guidance on the Company’s Consolidated Financial Statements.
Asset Retirement Obligations [Policy Text Block]	We recognize, at fair value, obligations associated with the retirement of certain tangible, long‑lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (AROs) relate primarily to the decommissioning of our coal-fired and wind energy facilities, and land reclamation at BNI Energy. AROs are included in Other Non-Current Liabilities on the Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives. Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal costs 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 commissions 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 the guidance 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 liability.
Equity Method Investments, Policy [Policy Text Block]	We account for our investment in ATC under the equity method of accounting.
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 2016 ($36.3 million in 2015; none in 2014).
Fair Value Measurement [Policy Text Block]	We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. 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. 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. 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). In accordance with accounting standards for earnings per share, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share in 2016, 2015 and 2014.
Pension and Other Postretirement Benefit Plans [Policy Text Block]	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. According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the above 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.
Employee Stock Ownership Plan [Policy Text Block]	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. With the maturity of the note, ESOP employer allocations will be funded with contributions paid in either cash or the issuance of ALLETE common stock at the Company’s discretion. According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock held and purchased by the ESOP were treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

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	2016		2015		2014
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$68.2		$59.0		$51.3
Cash Paid During the Period for Income Taxes		$0.5		$0.4		$5.1
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(22.0)		$(40.6)			$21.7
Capitalized Asset Retirement Costs		$3.7		$12.4	$22.4
Camp Ripley Solar Project Financing		$15.0	—		—
AFUDC–Equity		$2.1		$3.3		$7.8
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	—		—		$19.5
Contingent Consideration	—			$35.7	—
ALLETE Common Stock Received for Sale of Land Inventory		$8.0	—		—
Long-Term Finance Receivable for Land Inventory		$12.0	—		—

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2016		2015
Millions
Trade Accounts Receivable
Billed		$106.5		$105.3
Unbilled	19.1		16.9
Less: Allowance for Doubtful Accounts	3.1		1.0
Total Accounts Receivable		$122.5		$121.2

Inventories – Net [Table Text Block]



Inventories – Net
As of December 31	2016			2015
Millions
Fuel (a)		$43.9			$58.1
Materials and Supplies	48.7			49.1
Raw Materials	2.9			2.7
Work in Progress	1.0			—
Finished Goods	8.6			7.5
Reserve for Obsolescence	(0.9		)	(0.3		)
Total Inventories		$104.2			$117.1


(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	2016		2015
Millions
Deferred Fuel Adjustment Clause		$18.6		$10.6
Restricted Cash (a)	2.2		5.6
Other	19.5		19.5
Total Prepayments and Other Current Assets		$40.3		$35.7


(a)	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements 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	2016		2015
Millions
Contract Payment (a)		$29.6	—
Finance Receivable (b)	11.5		—
Restricted Cash (c)	8.6			$8.1
Other	56.8		60.0
Total Other Non-Current Assets		$106.5		$68.1


(a)	Contract Payment includes a $31.0 million 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 ALLETE Clean Energy’s loan agreements 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	2016		2015
Millions
Customer Deposits		$5.4		$15.1
Power Sales Agreements	24.6		23.3
Other	43.7		47.7
Total Other Current Liabilities		$73.7		$86.1

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities
As of December 31	2016		2015
Millions
Asset Retirement Obligation		$136.6		$131.4
Power Sales Agreements	113.8		138.1
Contingent Consideration (a)	25.0		36.6
Other	47.3		42.9
Total Other Non-Current Liabilities		$322.7		$349.0


(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	2016			2015		2014
Millions
Impairment of Real Estate (a)	—				$36.3	—
Impairment of Goodwill (b)		$3.3		—		—
Change in Fair Value of Contingent Consideration (c)	(13.6		)	—		—
Total Operating Expenses – Other	$(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, 2016

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	2016			2015
Millions
Regulated Operations
Property, Plant and Equipment in Service		$4,437.0			$4,336.7
Construction Work in Progress	84.2			101.2
Accumulated Depreciation	(1,426.1		)	(1,323.8		)
Regulated Operations – Net	3,095.1			3,114.1
ALLETE Clean Energy
Property, Plant and Equipment in Service	472.3			467.3
Construction Work in Progress (a)	101.0			4.0
Accumulated Depreciation	(41.0		)	(24.0		)
ALLETE Clean Energy – Net	532.3			447.3
U.S. Water Services
Property, Plant and Equipment in Service	19.5			15.6
Accumulated Depreciation	(6.9		)	(3.4		)
U.S. Water Services – Net	12.6			12.2
Corporate and Other (b)
Property, Plant and Equipment in Service	179.8			165.6
Construction Work in Progress	2.8			4.5
Accumulated Depreciation	(81.4		)	(74.6		)
Corporate and Other – Net	101.2			95.5
Property, Plant and Equipment – Net		$3,741.2			$3,669.1


(a)	The increase in ALLETE Clean Energy’s construction work in progress primarily relates to deposits for WTGs. The WTGs will be utilized as ALLETE Clean Energy develops future projects.


(b)	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	10 to 50 years	U.S. Water Services	3 to 39 years
Transmission	44 to 67 years	Corporate and Other	3 to 47 years
Distribution	18 to 65 years

Asset Retirement Obligations [Table Text Block]



Asset Retirement Obligations
Millions
Obligation as of December 31, 2014		$109.2
Accretion	7.3
Liabilities Recognized (a)	5.1
Liabilities Settled	(2.6		)
Revisions in Estimated Cash Flows	12.4
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


(a)	The increase in 2015 is related to the ALLETE Clean Energy wind energy facilities acquisitions in 2015. (See Note 6. Acquisitions.)

Jointly-Owned Facilities and Projects (Tables)

12 Months Ended

Dec. 31, 2016

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, 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
As of December 31, 2015
Boswell Unit 4		$668.2		$195.0		$6.9	80
CapX2020 Projects	101.1		3.4		—		9.3 - 14.7
Total		$769.3		$198.4		$6.9

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

Regulatory Assets [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2016		2015
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$18.6		$10.6
Total Current Regulatory Assets	18.6		10.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	226.1		219.3
Income Taxes (c)	63.3		64.2
Cost Recovery Riders (d)	30.5		58.0
Asset Retirement Obligations (e)	26.0		21.6
PPACA Income Tax Deferral	5.0		5.0
Other	8.7		3.9
Total Non-Current Regulatory Assets	359.6		372.0
Total Regulatory Assets		$378.2		$382.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$56.8		$58.0
North Dakota Investment Tax Credits (g)	28.2		12.8
Income Taxes (c)	19.1		6.1
Plant Removal Obligations	19.1		22.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	—		0.9
Other	2.6		5.1
Total Non-Current Regulatory Liabilities		$125.8		$105.0


(a)	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.

(b)


(c)	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. This balance will decrease over the remaining life of the related temporary differences and flow through current income taxes.

(d)


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


(f)	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.


(g)	North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers over the remaining life of Bison through future renewable cost recovery rider fillings.

Regulatory Liabilities [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2016		2015
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$18.6		$10.6
Total Current Regulatory Assets	18.6		10.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	226.1		219.3
Income Taxes (c)	63.3		64.2
Cost Recovery Riders (d)	30.5		58.0
Asset Retirement Obligations (e)	26.0		21.6
PPACA Income Tax Deferral	5.0		5.0
Other	8.7		3.9
Total Non-Current Regulatory Assets	359.6		372.0
Total Regulatory Assets		$378.2		$382.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$56.8		$58.0
North Dakota Investment Tax Credits (g)	28.2		12.8
Income Taxes (c)	19.1		6.1
Plant Removal Obligations	19.1		22.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	—		0.9
Other	2.6		5.1
Total Non-Current Regulatory Liabilities		$125.8		$105.0


(a)	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.

(b)


(c)	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. This balance will decrease over the remaining life of the related temporary differences and flow through current income taxes.

(d)


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


(f)	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.


(g)	North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers over the remaining life of Bison through future renewable cost recovery rider fillings.

Investment in ATC (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

ALLETE's Investment in ATC [Table Text Block]



ALLETE’s Investment in ATC
Year Ended December 31	2016			2015
Millions
Equity Investment Beginning Balance		$124.5			$121.1
Cash Investments	5.4			1.6
Equity in ATC Earnings	18.5			16.3
Distributed ATC Earnings	(12.8		)	(14.5		)
Equity Investment Ending Balance		$135.6			$124.5



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2016		2015
Millions
Current Assets		$75.8		$80.5
Non-Current Assets	4,312.9		3,957.6
Total Assets		$4,388.7		$4,038.1
Current Liabilities		$495.1		$330.3
Long-Term Debt	1,865.3		1,800.0
Other Non-Current Liabilities	271.5		245.0
Members’ Equity	1,756.8		1,662.8
Total Liabilities and Members’ Equity		$4,388.7		$4,038.1



Income Statement Data
Year Ended December 31	2016		2015		2014
Millions
Revenue		$650.8		$615.8		$635.0
Operating Expense	322.5		319.3		307.4
Other Expense	95.5		96.1		88.9
Net Income		$232.8		$200.4		$238.7
ALLETE’s Equity in Net Income		$18.5		$16.3		$19.6

Acquisitions Acquisitions (Tables)

12 Months Ended

Dec. 31, 2016

Water & Energy Systems Technology [Member]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$0.1
Other Current Assets	1.1
Customer Relationships (a)	2.8
Goodwill (b)	3.9
Other Non-Current Assets	0.1
Total Assets Acquired		$8.0
Liabilities Assumed
Current Liabilities		$0.2
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.4
Net Identifiable Assets Acquired		$6.6


(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 [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 [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
Power Sales Agreements	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 [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 [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.

ACE Wind [Member]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	14.3
Property, Plant and Equipment	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
Current Liabilities (b)		$15.2
Long-Term Debt Due Within One Year	2.2
Long-Term Debt	21.1
Power Sales Agreements	99.4
Other Non-Current Liabilities	10.6
Non-Controlling Interest (c)	7.1
Total Liabilities and Non-Controlling Interest Assumed	$155.6
Net Identifiable Assets Acquired		$26.9


(a)	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain, and goodwill of $2.9 million. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Current Liabilities included $12.4 million related to the current portion of PSAs.


(c)	The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method.

Storm Lake I [Member]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Current Liabilities (b)		$8.2
Power Sales Agreements	23.5
Non-Current Liabilities	17.0
Total Liabilities Assumed	$48.7
Net Identifiable Assets Acquired		$15.1


(a)	Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Current Liabilities included $7.5 million related to the current portion of PSAs.

Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2016

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, 2014		$2.9		—			$2.9
Acquired Goodwill (a)	0.4				$127.3	127.7
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


(a)	See Note 6. Acquisitions.

(b)

Schedule of Intangible Assets [Table Text Block]

The following table summarizes changes to intangible assets, net, for the year ended December 31, 2016:



	December 31, 2015		Additions (a)		Amortization	December 31, 2016
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$60.8		$2.8	$(4.3)		$59.3
Developed Technology and Other (b)	7.2		—		(0.9)	6.3
Total Definite-Lived Intangible Assets	68.0		2.8		(5.2)	65.6
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$84.6		$2.8	$(5.2)		$82.2


(a)	Additions resulting from the October 11, 2016, acquisition of WEST. (See Note 6. Acquisitions.)


(b)	Developed Technology and Other includes patents, non-compete agreements and land easements.

Fair Value (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.6	—		—			$7.6
Available-for-sale – Corporate Debt Securities	—			$10.9	—		10.9
Cash Equivalents	2.0		—		—		2.0
Total Fair Value of Assets		$9.6		$10.9	—			$20.5

Liabilities: (b)
Deferred Compensation	—			$16.1	—			$16.1
U.S. Water Services Contingent Consideration	—		—			$36.6	36.6
Total Fair Value of Liabilities	—			$16.1		$36.6		$52.7
Total Net Fair Value of Assets (Liabilities)		$9.6	$(5.2)		$(36.6)		$(32.2)


(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.

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, 2014	—
Recognition of U.S. Water Services Contingent Consideration		$35.7
Accretion (a)	2.4
Payments	(0.1		)
Changes in Cash Flow Projections	(1.4		)
Balance as of December 31, 2015		$36.6
Accretion (a)	2.8
Payments	(0.8		)
Changes in Cash Flow Projections	(13.6		)
Balance as of December 31, 2016		$25.0


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

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, 2016	$1,569.1	$1,653.8
December 31, 2015	$1,605.0	$1,676.0

Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Long-term Debt [Table Text Block]



Long-Term Debt
As of December 31	2016			2015
Millions
First Mortgage Bonds
7.70% Series Due 2016	—			$20.0
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			125.0
Senior Unsecured Notes 5.99% Due 2017	50.0			50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020	13.5			13.5
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8			27.8
Armenia Mountain Senior Secured Notes 3.26% Due 2024	74.6			83.3
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0			15.0
Other Long-Term Debt, 3.11% – 6.20% Due 2017 – 2037	61.2			68.4
Unamortized Debt Issuance Costs	(11.0		)	(12.6		)
Total Long-Term Debt	1,558.1			1,592.4
Less: Due Within One Year	187.7			35.7
Net Long-Term Debt		$1,370.4			$1,556.7

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees and Contingencies Commitments, Guarantees and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

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

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



As of December 31, 2016
Millions	2017		2018		2019		2020		2021		Thereafter
Coal, Rail and Shipping Contracts		$27.9		$27.0		$1.8	—		—		—
Leasing Agreements		$13.7		$12.0		$10.7		$7.5		$5.9		$18.3
PPAs (a)		$98.0		$102.9		$105.5		$113.4		$143.3		$1,803.9


(a)	Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only, and the 133 MW agreement with Manitoba Hydro commencing in 2020, as our obligation under this contract is subject to construction of additional transmission capacity. Also excludes Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered.

Minnesota Power has also entered into the following agreements for the purchase or sale of capacity and energy as of December 31, 2016:



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
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(j)
PSA 2	100 MW	Capacity	June 2016	June 2018	Fixed
Minnkota Power	(k)	Capacity / Energy	June 2014	December 2026	(k)
Silver Bay Power	(l)	Energy	January 2017	December 2031	(m)


(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 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.

(k)

(l)


(m)	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, 2016

Equity [Abstract]

Summary of Common Stock [Table Text Block]



Summary of Common Stock	Shares		Equity
	Thousands		Millions
Balance as of December 31, 2013	41,401			$885.2
Employee Stock Purchase Program	18		0.8
Invest Direct	378		18.9
Options and Stock Awards	78		8.0
Equity Issuance Program	1,851		90.0
Forward Sale Agreement and Issuance	1,807		85.2
Contributions to Pension	396		19.5
Balance as of December 31, 2014	45,929		1,107.6
Employee Stock Purchase Program	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 Program	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

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
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
2014
Net Income Attributable to ALLETE		$124.8			$124.8
Average Common Shares	42.9		0.2	43.1
Earnings Per Share		$2.91			$2.90

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2016			2015			2014
Millions
Current Tax Expense (a)
Federal	—			—			$1.1
State	$0.4			$0.2			2.9
Total Current Tax Expense		$0.4			$0.2			$4.0
Deferred Tax Expense
Federal		$12.0			$19.4			$25.3
State	8.1			6.5			8.2
Investment Tax Credit Amortization	(0.7		)	(0.8		)	(0.8		)
Total Deferred Tax Expense		$19.4			$25.1			$32.7
Total Income Tax Expense		$19.8			$25.3			$36.7

(a)

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	2016			2015			2014
Millions
Income Before Non-Controlling Interest and Income Taxes		$175.6			$166.8			$162.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$61.5			$58.4			$56.8
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	5.6			4.4			7.2
Regulatory Differences for Utility Plant	(0.1		)	(0.6		)	(3.5		)
Production Tax Credits	(41.5		)	(37.0		)	(23.7		)
Change in Fair Value of Contingent Consideration	(3.8		)	—			—
Other	(1.9		)	0.1			(0.1		)
Total Income Tax Expense		$19.8			$25.3			$36.7

Deferred Tax Assets and Liabilities [Table Text Block]



Deferred Tax Assets and Liabilities
As of December 31	2016			2015
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$104.6			$105.4
Property Related	117.8			126.6
NOL Carryforwards	185.6			186.4
Tax Credit Carryforwards	227.4			164.8
Power Sales Agreements	59.3			73.0
Other	46.9			21.8
Gross Deferred Tax Assets	741.6			678.0
Deferred Tax Asset Valuation Allowance	(43.0		)	(31.6		)
Total Deferred Tax Assets		$698.6			$646.4
Deferred Tax Liabilities
Property Related		$1,094.7			$1,053.0
Regulatory Asset for Benefit Obligations	91.9			89.4
Unamortized Investment Tax Credits	33.3			26.0
Partnership Basis Differences	50.9			47.8
Other	11.9			10.0
Total Deferred Tax Liabilities		$1,282.7			$1,226.2
Net Deferred Income Taxes (a)		$584.1			$579.8


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

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
As of December 31	2016	2015
Millions
Federal NOL Carryforwards (a)	$485.3		$493.0
Federal Tax Credit Carryforwards	$163.7	$113.6
State NOL Carryforwards (a)	$294.4	$228.6
State Tax Credit Carryforwards (b)	$21.0	$20.0


(a)	Pre-tax amounts.


(b)	Net of a $42.7 million valuation allowance as of December 31, 2016 ($31.2 million as of December 31, 2015).

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
As of December 31	2016	2015
Millions
Federal NOL Carryforwards (a)	$485.3		$493.0
Federal Tax Credit Carryforwards	$163.7	$113.6
State NOL Carryforwards (a)	$294.4	$228.6
State Tax Credit Carryforwards (b)	$21.0	$20.0


(a)	Pre-tax amounts.


(b)	Net of a $42.7 million valuation allowance as of December 31, 2016 ($31.2 million as of December 31, 2015).

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2016			2015			2014
Millions
Balance at January 1		$2.4			$2.0			$1.2
Additions for Tax Positions Related to the Current Year	0.1			0.5			—
Additions for Tax Positions Related to Prior Years	0.2			0.7			1.0
Reductions for Tax Positions Related to Prior Years	(0.3		)	(0.7		)	—
Lapse of Statute	(0.4		)	(0.1		)	(0.2		)
Balance as of December 31		$2.0			$2.4			$2.0

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

12 Months Ended

Dec. 31, 2016

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, 2016, 2015 and 2014, 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, 2013	$(0.1)		$(16.7)		$(0.3)		$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.3	)	(5.2	)	0.2		(5.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	0.1		1.2		—		1.3
Net Other Comprehensive Income (Loss)	(0.2	)	(4.0	)	0.2		(4.0	)
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)


(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, 2016

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2017		$45.0		$9.3
2018		$45.2		$9.4
2019		$45.4		$9.7
2020		$45.5		$9.9
2021		$45.8		$10.0
Years 2022 – 2026		$231.0		$51.4

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	$9.9	$0.3
Prior Service Credit	—	(2.0)
Total Pension and Postretirement Health and Life Cost (Credit)	$9.9	$(1.7)

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



Assumptions Used to Determine Benefit Obligation
As of December 31	2016	2015
Discount Rate
Pension	4.53%	4.72%
Postretirement Health and Life	4.57%	4.73%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	5.00 - 7.00%	6.50%
Ultimate Trend Rate	4.50%	5.00%
Year Ultimate Trend Rate Effective	2038	2022

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



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2016	2015	2014
Discount Rate	4.72 - 4.73%	4.30 - 4.33%	4.93 - 4.96%
Expected Long-Term Return on Plan Assets (a)
Pension	8.00%	8.00%	8.00%
Postretirement Health and Life	6.40 - 8.00%	6.40 - 8.00%	6.40 - 8.00%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%	3.70 - 4.30%


(a)	The expected long-term rates of return used to determine net periodic benefit expense for 2017 have been reduced to 7.50 percent for pension expense and 6.00 percent to 7.50 percent for postretirement health and life expense.

Plan Asset Actual and Target Allocations [Table Text Block]

Following are the current targeted allocations as of December 31, 2016:



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.



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2016		2015		2016		2015
Equity Securities	49	%	47	%	60	%	57	%
Debt Securities	39	%	39	%	34	%	35	%
Private Equity	7	%	8	%	6	%	8	%
Real Estate	5	%	6	%	—		—
	100	%	100	%	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	2016			2015
Millions
Accumulated Benefit Obligation		$698.8			$665.0
Change in Benefit Obligation
Obligation, Beginning of Year		$709.8			$714.5
Service Cost	8.1			10.1
Interest Cost	33.2			29.9
Actuarial (Gain) Loss	12.4			(31.2		)
Benefits Paid	(44.5		)	(40.2		)
Participant Contributions	24.3			26.7
Obligation, End of Year		$743.3			$709.8
Change in Plan Assets
Fair Value, Beginning of Year		$521.3			$544.2
Actual Return on Plan Assets	48.8			(10.8		)
Employer Contribution (a)	31.9			28.1
Benefits Paid	(44.5		)	(40.2		)
Fair Value, End of Year		$557.5			$521.3
Funded Status, End of Year	$(185.8)			$(188.5)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.4)			$(1.3)
Non-Current Liabilities	$(184.4)			$(187.2)


(a)	Includes Participant Contributions noted above.

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Pension Expense
Year Ended December 31	2016			2015			2014
Millions
Service Cost		$8.1			$10.1			$8.3
Interest Cost	33.2			29.9			29.8
Expected Return on Plan Assets	(43.6		)	(40.7		)	(38.2		)
Amortization of Loss	9.5			17.9			14.2
Amortization of Prior Service Cost	—			0.2			0.3
Net Pension Expense		$7.2			$17.4			$14.4

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	2016		2015
Millions
Net Loss	$7.2			$20.2
Amortization of Prior Service Cost	—		(0.2		)
Amortization of Loss	(9.5	)	(17.9		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$(2.3)			$2.1

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	2016		2015
Millions
Projected Benefit Obligation		$743.3		$709.8
Accumulated Benefit Obligation		$698.8		$665.0
Fair Value of Plan Assets		$557.5		$521.3

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$33.9		$42.1	—			$76.0
U.S. Mid-cap Growth (a)	14.2		17.7		—		31.9
U.S. Small-cap (a)	14.5		17.9		—		32.4
Mutual Funds	8.4		—		—		8.4
International	44.7		42.0		—		86.7
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		185.3		—		188.0
Cash and Cash Equivalents	25.6		—		—		25.6
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$144.1		$305.0		$72.2		$521.3

(a)



	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)

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, 2014		$43.3			$28.9
Actual Return on Plan Assets	2.6			2.9
Purchases, Sales, and Settlements – Net	(2.6		)	(2.9		)
Balance as of December 31, 2015		$43.3			$28.9



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

Obligation and Funded Status [Table Text Block]



Postretirement Health and Life Obligation and Funded Status
As of December 31	2016			2015
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$160.2			$170.9
Service Cost	3.9			4.3
Interest Cost	7.4			7.2
Actuarial (Gain) Loss	11.9			(14.4		)
Benefits Paid	(13.1		)	(10.7		)
Participant Contributions	3.1			2.9
Obligation, End of Year		$173.4			$160.2
Change in Plan Assets
Fair Value, Beginning of Year		$153.4			$163.2
Actual Return on Plan Assets	9.6			(3.5		)
Employer Contribution	1.3			1.5
Participant Contributions	3.1			2.9
Benefits Paid	(13.1		)	(10.7		)
Fair Value, End of Year		$154.3			$153.4
Funded Status, End of Year	$(19.1)			$(6.8)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$1.4			$6.4
Current Liabilities	$(1.1)			$(1.0)
Non-Current Liabilities	$(19.4)			$(12.2)

Unrecognized Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
As of December 31	2016		2015
Millions
Net Loss	$19.8		$6.5
Prior Service Credit	(4.7	)	(7.6	)
Total Unrecognized Postretirement Health and Life Cost (Credit)	$15.1		$(1.1)

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2016			2015			2014
Millions
Service Cost		$3.9			$4.3			$3.4
Interest Cost	7.4			7.2			7.3
Expected Return on Plan Assets	(11.2		)	(10.9		)	(10.3		)
Amortization of Loss	0.2			0.4			0.5
Amortization of Prior Service Credit	(2.9		)	(3.0		)	(2.5		)
Net Postretirement Health and Life Credit	$(2.6)			$(2.0)			$(1.6)

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	2016			2015
Millions
Net Loss		$13.5		—
Amortization of Prior Service Credit	2.9				$3.0
Amortization of Loss	(0.2		)	(0.4		)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$16.2			$2.6

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		$20.1	$(16.7)
Effect on Postretirement Health and Life Obligation		$1.8	$(1.4)

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)		$27.9	—		—			$27.9
U.S. Mid-cap Growth (a)	20.7		—		—		20.7
U.S. Small-cap (a)	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 classified under U.S. Equity Securities consist of mutual funds (Level 1).



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$28.2	—		—			$28.2
U.S. Mid-cap Growth (a)	19.1		—		—		19.1
U.S. Small-cap (a)	12.1		—		—		12.1
International	26.8		—		—		26.8
Debt Securities:
Mutual Funds	45.2		—		—		45.2
Fixed Income	—			$8.4	—		8.4
Cash and Cash Equivalents	1.6		—		—		1.6
Private Equity Funds	—		—			$12.0	12.0
Total Fair Value of Assets		$133.0		$8.4		$12.0		$153.4


(a)	The underlying investments classified under U.S. Equity Securities 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, 2014		$12.9
Actual Return on Plan Assets	1.2
Purchases, Sales, and Settlements – Net	(2.1		)
Balance as of December 31, 2015		$12.0



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

Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2016

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

Employee Stock Ownership Plan [Table Text Block]



As of December 31	2016	2015	2014
Millions
ESOP Shares
Allocated	1.6	1.8	1.9
Unallocated	—	—	0.3
Total	1.6	1.8	2.2
Fair Value of Unallocated Shares	—	—		$13.2

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	2016		2015		2014
Millions
Performance Shares		$1.8		$1.8		$1.6
Restricted Stock Units	0.8		0.8		0.7
Total Share-Based Compensation Expense		$2.6		$2.6		$2.3
Income Tax Benefit		$1.1		$1.1		$1.0

Non-Qualified Stock Options [Table Text Block]

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



	2016				2015				2014
	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	39,654			$44.39	66,279			$44.39	108,299			$44.10
Granted (a)	—		—		—		—		—		—
Exercised	(35,297	)		$44.89	(24,456	)		$44.52	(42,020	)		$43.65
Forfeited	—		—		(2,169	)	$42.93		—		—
Outstanding as of December 31	4,357			$40.29	39,654			$44.39	66,279			$44.39
Exercisable as of December 31	4,357			$40.29	39,654			$44.39	66,279			$44.39


(a)	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Stock Options by Exercise Price Range [Table Text Block]



	Exercise Price
As of December 31, 2016	$39.10		$48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	3,816		541
Weighted Average Remaining Contractual Life (Years)	1.1		0.1
Weighted Average Exercise Price		$39.10		$48.65
Aggregate Intrinsic Value (Millions)		$0.1	—

Performance Shares [Table Text Block]

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



	2016				2015				2014
	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	119,540			$52.72	119,635			$48.26	114,765			$47.02
Granted (a)	57,189			$52.43	43,583			$58.95	47,992			$46.47
Awarded	—		—		—		—		(36,515	)		$42.01
Unearned Grant Award	(42,126	)		$52.70	(36,670	)		$45.41	—		—
Forfeited	(7,023	)		$53.45	(7,008	)		$53.49	(6,607	)		$48.29
Non-vested as of December 31	127,580			$52.56	119,540			$52.72	119,635			$48.26

(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.



	2016				2015				2014
	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	57,694			$49.86	53,888			$44.47	55,982			$40.85
Granted (a)	20,351			$50.25	26,702			$54.81	19,645			$48.44
Awarded	(19,661	)		$44.33	(19,464	)		$41.44	(18,860	)		$37.64
Forfeited	(3,656	)		$52.87	(3,432	)		$51.52	(2,879	)		$45.92
Available as of December 31	54,728			$51.79	57,694			$49.86	53,888			$44.47

(a) Shares granted include accrued dividends.

Business Segments (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Business Segments [Table Text Block]



Year Ended December 31	2016			2015			2014
Millions
Operating Revenue
Regulated Operations		$1,000.7			$991.2			$1,003.5

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	80.5			262.1			33.2
U.S. Water Services	137.5			119.8			—

Corporate and Other	121.0			113.3			100.1
Total Operating Revenue		$1,339.7			$1,486.4			$1,136.8
Net Income (Loss) Attributable to ALLETE
Regulated Operations (b)		$135.5			$131.6			$123.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	13.4			29.9			3.3
U.S. Water Services	1.5			0.9			—

Corporate and Other (b)	4.9			(21.3		)	(1.5		)
Total Net Income Attributable to ALLETE		$155.3			$141.1			$124.8
Depreciation and Amortization
Regulated Operations		$154.3			$135.1			$118.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	22.3			18.7			10.1
U.S. Water Services	8.9			7.3			—

Corporate and Other	10.3			8.9			7.6
Total Depreciation and Amortization		$195.8			$170.0			$135.7
Operating Expenses – Other (c)
ALLETE Clean Energy	$3.3			—			—
Corporate and Other	(13.6		)	$36.3			—
Total Operating Expenses – Other	$(10.3)			$36.3			—
Interest Expense
Regulated Operations (b)	$52.1			$53.9			$49.2

Energy Infrastructure and Related Services
ALLETE Clean Energy	5.8			3.3			0.8
U.S. Water Services	1.7			1.4			—

Corporate and Other (b)	14.5			8.6			7.1

Eliminations (b)	(3.8		)	(2.3		)	(2.3		)
Total Interest Expense	$70.3			$64.9			$54.8
Equity Earnings in ATC
Regulated Operations	$18.5			$16.3			$19.6


(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)	During 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries. The amounts are eliminated in consolidation.


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



As of December 31	2016		2015
Millions
Assets
Regulated Operations (a)	$3,853.4		$3,853.1

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	566.0		501.5
U.S. Water Services	264.1		258.3

Corporate and Other	222.9		281.6
Total Assets (a)		$4,906.4		$4,894.5
Capital Expenditures
Regulated Operations	$121.8		$224.4

Energy Infrastructure and Related Services
ALLETE Clean Energy	106.9		8.6
U.S. Water Services	3.7		2.9

Corporate and Other	15.4		15.9
Total Capital Expenditures		$247.8		$251.8


(a)	As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been reclassified to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)



Year Ended December 31	2016		2015			2014
Millions
Income Tax Expense (Benefit)
Regulated Operations		$5.9		$24.4			$39.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	8.1		21.0			2.3
U.S. Water Services	1.4		0.9			—

Corporate and Other	4.4		(21.0		)	(4.6		)
Total Income Tax Expense		$19.8		$25.3			$36.7

Operations and Significant Accounting Policies - Business Segments (Details)	12 Months Ended
	Dec. 31, 2016 a Customers MW	Dec. 31, 2015 MW
Business Segments [Line Items]
Number of Reportable Segments	3
Square Butte [Member] \| Square Butte PPA [Member]
Business Segments [Line Items]
Output Purchased (Percent)	50.00%
Output Being Purchased (MW) \| MW	227.5
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 (MW) \| MW	535
Generating Capacity Constructed and Sold (MW) \| MW		107
ALLETE Clean Energy [Member] \| ALLETE Clean Energy [Member] \| ALLETE Clean Energy PSA - Future Development Project [Member]
Business Segments [Line Items]
Future Generating Capacity Under Development (MW) \| MW	50
PSA Term (Years)	25 years
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$ 68.2	$ 59.0	$ 51.3
Cash Paid During the Period for Income Taxes	0.5	0.4	5.1
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	(22.0)	(40.6)
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment			21.7
Capitalized Asset Retirement Costs	3.7	12.4	22.4
Camp Ripley Solar Project Financing	15.0	0.0	0.0
AFUDC–Equity	2.1	3.3	7.8
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	0.0	0.0	19.5
Contingent Consideration	0.0	35.7	0.0
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	8.0	0.0	0.0
Long-Term Finance Receivable for Land Inventory [Member]
Noncash Consideration for Land Inventory [Line Items]
Consideration for Land Inventory	$ 12.0	$ 0.0	$ 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, 2016 USD ($) Customers	Dec. 31, 2015 USD ($)	Dec. 31, 2014
Concentration Risk [Line Items]
Number of Customers	9
Accounts Receivable \| $	$ 9.5	$ 9.2
Largest Customer [Member]
Concentration Risk [Line Items]
Number of Customers	1
Largest Customer [Member] \| Consolidated Operating Revenue [Member]
Concentration Risk [Line Items]
Percent of Consolidated Operating Revenue	8.00%	8.00%	12.00%

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Trade Accounts Receivable [Abstract]

Billed

$ 106.5

$ 105.3

Unbilled

19.1

16.9

Less: Allowance for Doubtful Accounts

3.1

1.0

Total Accounts Receivable

122.5

121.2

Inventories – Net [Abstract]

Fuel

^[1]

43.9

58.1

Materials and Supplies

48.7

49.1

Raw Materials

2.9

2.7

Work in Progress

1.0

0.0

Finished Goods

8.6

7.5

Reserve for Obsolescence

(0.9)

(0.3)

Total Inventories

104.2

117.1

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

18.6

10.6

Restricted Cash

^[2]

2.2

5.6

Total Prepayments and Other Current Assets

19.5

40.3

35.7

Impairment of Long-Lived Assets [Abstract]

3,741.2

3,669.1

Impairment of Real Estate

^[3]

0.0

36.3

$ 0.0

Indefinite-Lived Intangible Assets [Abstract]

^[4]

3.3

^[5]

0.0

Impairment of Intangible Assets

0.0

Other Non-Current Assets [Abstract]

Contract Payment

^[6]

29.6

0.0

Financing Receivable

^[7]

11.5

0.0

Restricted Cash

^[8]

8.6

8.1

Total Other Non-Current Assets

56.8

60.0

106.5

68.1

Contract Payment Made to Cliffs

31.0

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]

Customer Deposits

$ 5.4

15.1

Power Sales Agreements

24.6

23.3

Total Other Current Liabilities

43.7

47.7

73.7

86.1

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

136.6

131.4

Power Sales Agreements

113.8

138.1

Contingent Consideration

^[9]

25.0

36.6

Total Other Non-Current Liabilities

47.3

42.9

322.7

349.0

Amortization of Power Sales Agreements

22.3

23.2

12.7

Operating Expenses – Other [Abstract]

Impairment of Real Estate

^[3]

0.0

36.3

0.0

Change in Fair Value of Contingent Consideration

^[4]

3.3

^[5]

0.0

^[10]

(13.6)

0.0

Total Operating Expenses – Other

$ (10.3)

36.3

0.0

Income Taxes [Abstract]

More-Likely-Than-Not Percentage

50.00%

Regulated Operations [Member]

$ 3,095.1

3,114.1

Alternative Revenue Program, Required Collection Period (Months)

24 months

$ 532.3

447.3

3.3

^[5]

0.0

Amortization of Power Sales Agreements

22.3

23.2

12.7

Operating Expenses – Other [Abstract]

3.3

^[5]

0.0

12.6

12.2

$ 0.0

^[5]

0.0

Reporting Unit Fair Value in Excess of Carrying Value

10.75%

Terminal Growth Rate

5.00%

10.00%

Operating Expenses – Other [Abstract]

Corporate and Other [Member]

$ 0.0

^[5]

0.0

$ 101.2

95.5

Minimum Cash Collections Requirement for Real Estate Sales (Percent)

20.00%

Minimum [Member]

Definite-Lived Intangible Assets [Line Items]

Minimum [Member] | ALLETE Clean Energy [Member]

2 years

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

8.25%

Annual Revenue Growth Rate

8.00%

Maximum [Member]

Definite-Lived Intangible Assets [Line Items]

Maximum [Member] | ALLETE Clean Energy [Member]

21 years

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

9.25%

Annual Revenue Growth Rate

11.00%

Wind Turbine Generators [Member] | ALLETE Clean Energy [Member]

Impairment of Long-Lived Assets [Abstract]

Indicators of Impairment

$ 0.0

Taconite Harbor [Member]

Boswell Units 1 and 2 [Member]

$ 90.0

$ 30.0

[1]	Fuel consists primarily of coal inventory at Minnesota Power.
[2]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and collateral deposits required for U.S. Water Services’ standby letters of credit.
[3]	See Impairment of Long-Lived Assets.
[4]	See Goodwill and Intangible Assets.
[5]	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 January 2014.
[6]	Contract Payment includes a $31.0 million 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.)
[7]	On September 22, 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.
[8]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.
[9]	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.)
[10]	See Note 9. Fair Value.

Operations and Significant Accounting Policies - New Accounting Standards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Presentation of Debt Issuance Costs [Member] \| Total Assets [Member]
New Accounting Standards [Line Items]
Effect of the Adoption		$ (12.6)
Presentation of Debt Issuance Costs [Member] \| Total Liabilities [Member]
New Accounting Standards [Line Items]
Effect of the Adoption		$ (12.6)
Income Tax Expense (Benefit) [Member] \| Maximum [Member] \| Improvements to Employee Share-Based Payment Accounting [Member]
New Accounting Standards [Line Items]
Effect of the Adoption	$ 1.0

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Asset Retirement Obligation [Roll Forward]

$ 3,741.2

$ 3,669.1

Beginning Obligation

131.4

109.2

Accretion

8.0

7.3

Liabilities Recognized

^[1]

5.1

Liabilities Settled

(6.5)

(2.6)

Revisions in Estimated Cash Flows

3.7

12.4

Ending Obligation

136.6

131.4

Regulated Operations [Member]

Construction Work in Progress

4,437.0

4,336.7

84.2

101.2

(1,426.1)

(1,323.8)

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

$ 3,095.1

3,114.1

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

10 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

$ 472.3

467.3

101.0

^[2]

4.0

(41.0)

(24.0)

ALLETE Clean Energy [Member] | Minimum [Member]

$ 532.3

447.3

ALLETE Clean Energy [Member] | Maximum [Member]

5 years

35 years

$ 19.5

15.6

(6.9)

(3.4)

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

$ 12.6

12.2

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

3 years

Corporate and Other [Member]

39 years

Construction Work in Progress

^[3]

$ 179.8

165.6

^[3]

2.8

4.5

^[3]

(81.4)

(74.6)

Corporate and Other [Member] | Minimum [Member]

$ 101.2

$ 95.5

Corporate and Other [Member] | Maximum [Member]

3 years

47 years

[1]	The increase in 2015 is related to the ALLETE Clean Energy wind energy facilities acquisitions in 2015. (See Note 6. Acquisitions.)
[2]	The increase in ALLETE Clean Energy’s construction work in progress primarily relates to deposits for WTGs. The WTGs will be utilized as ALLETE Clean Energy develops future projects.
[3]	Primarily includes BNI Energy and a small amount of non-rate base generation.

Jointly-Owned Facilities and Projects (Details) $ in Millions	Dec. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 769.3	$ 769.3
Accumulated Depreciation	217.1	198.4
Construction Work in Progress	$ 8.1	6.9
Transmission [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	3
Plant in Service	$ 101.2	101.1
Accumulated Depreciation	5.9	3.4
Construction Work in Progress	$ 0.0	$ 0.0
Transmission [Member] \| CapX2020 Projects [Member] \| Minimum [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	9.30%	9.30%
Transmission [Member] \| CapX2020 Projects [Member] \| Maximum [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	14.70%	14.70%
Boswell Unit 4 [Member] \| Generation [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	80.00%	80.00%
Generating Capacity (MW) \| MW	585
% Not Owned	20.00%
Plant in Service	$ 668.1	$ 668.2
Accumulated Depreciation	211.2	195.0
Construction Work in Progress	$ 8.1	$ 6.9

Regulatory Matters - Electric Rates (Details) $ in Millions				12 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Dec. 12, 2016 USD ($)	Nov. 02, 2016 USD ($)	Jun. 28, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) Customers Years MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
PSCW [Member] \| 2012 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity					10.90%
PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)			3.10%
Requested Return on Equity			10.90%
Requested Equity Ratio			55.00%
Annual Additional Revenue Generated from Requested Final Rate Increase			$ 2.7
Electric Rates [Member] \| MPUC [Member] \| 2010 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity					10.38%
Approved Equity Ratio					54.29%
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					$ 97.1	$ 89.6	$ 71.8
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		53.80%
Annual Additional Revenue Generated from Requested Final Rate Increase		$ 55.0
Annual Additional Revenue Generated from Requested Interim Rate Increase	$ 34.7	49.0
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Subsequent Event [Member]
Regulatory Matters [Line Items]
Annual Additional Revenue Generated from Requested Interim Rate Increase				$ 34.7
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Boswell Energy Center [Member]
Regulatory Matters [Line Items]
Expected Increase (Decrease) in Annual Depreciation Expense		$ (25.0)
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					8.8
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Reduction in Operating Revenue due to Regulatory Outcome					15.0
Electric Rates [Member] \| MPUC [Member] \| Annual Automatic Adjustment of Charges [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Retail Fuel Cost Recovery Collected but Subject to Refund					$ 350.0
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
Notice Required to Terminate (Years) \| Years					3
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (expire December 2024) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers					14
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (expire December 2024) [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Change in Annual Capacity Charge Per Contract, Percentage					(1.00%)
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (expire December 2024) [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Change in Annual Capacity Charge Per Contract, Percentage					2.00%
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]
Number of Customers \| Customers					1
Average Monthly Demand (MW) \| MW					29
Electric Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)			3.50%
Natural Gas Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)			(1.30%)
Water Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)			7.80%

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - Integrated Resource Plan [Member] - Natural Gas-Fired [Member] - Minnesota Power [Member]	Dec. 31, 2016 MW
Minimum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	200
Maximum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	300

Regulatory Matters - Great Northern Transmission Line (Details) - Great Northern Transmission Line [Member]	Dec. 31, 2016 kV Miles
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Regulatory Matters [Line Items]
Annual Energy-Savings Goal	1.50%
Minimum [Member]
Regulatory Matters [Line Items]
CIP Spending Requirement	1.50%
CIP Triennial Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Investment Goal	$ 7.3	$ 7.1	$ 6.9
Actual Spending	7.4	6.6	7.2
Investment Goal in 2017	10.6
Investment Goal in 2018	10.8
Investment Goal in 2019	10.9
CIP Consolidated Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Financial Incentive	$ 7.5	$ 6.2	$ 8.7

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Dec. 31, 2016
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%
Maximum [Member] \| Incentive Adder [Member]
Loss Contingencies [Line Items]
Incentive Adder for Participation in Regional Transmission Organization (Basis Points)	50

Regulatory Matters - Minnesota Solar Energy Standard (Details) - MPUC [Member]	Dec. 31, 2016 Projects MW
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Overall Mandate Percentage	1.50%
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%
Maximum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.02
Minnesota Solar Energy Standard [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Number of Completed Projects \| Projects	1
Solar Energy Standard Mandate - Percentage of Overall Mandate Expected to be Met with Current Filings or Projects	33.33%
Minnesota Solar Energy Standard - Camp Ripley Project [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	10
Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	1
Minnesota Solar Energy Standard - Community Solar Garden Project - Owned and Operated [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	0.04

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

Current Regulatory Assets

$ 18.6

$ 10.6

359.6

372.0

Total Regulatory Assets

378.2

382.6

Wholesale and Retail Contra AFUDC [Member]

125.8

105.0

North Dakota Investment Tax Credits [Member]

^[1]

56.8

58.0

^[2]

28.2

12.8

Income Taxes [Member]

Plant Removal Obligations [Member]

^[3]

19.1

6.1

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

19.1

22.1

^[4]

0.0

0.9

Other [Member]

Deferred Fuel Adjustment Clause [Member]

2.6

5.1

Current Regulatory Assets

^[5]

18.6

10.6

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

^[4]

226.1

219.3

Income Taxes [Member]

Cost Recovery Riders [Member]

^[3]

63.3

64.2

Alternative Revenue Program, Required Collection Period (Years)

^[6]

$ 30.5

58.0

2 years

Asset Retirement Obligation [Member]

PPACA Income Tax Deferral [Member]

^[7]

$ 26.0

21.6

5.0

Other [Member]

$ 8.7

$ 3.9

[1]	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.
[2]	North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers over the remaining life of Bison through future renewable cost recovery rider fillings.
[3]	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. This balance will decrease over the remaining life of the related temporary differences and flow through current income taxes.
[4]	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.)
[5]	Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet.
[6]	The cost recovery rider regulatory assets are revenues not yet collected from our customers primarily due to capital expenditures related to Bison, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets as of December 31, 2016, will be recovered within the next two years.
[7]	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.

Investment in ATC (Details) $ in Millions		12 Months Ended
Investment in ATC (Details) $ in Millions	Jan. 29, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 27, 2016
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance		$ 124.5
Cash Investments		5.4	$ 1.6	$ 3.9
Equity Earnings in ATC		18.5	16.3	19.6
Equity Investment Ending Balance		135.6	124.5
Income Statement Data [Abstract]
ALLETE's Equity in Net Income		$ 18.5	16.3	19.6
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 2017		$ 10.9
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance		124.5	121.1
Cash Investments		5.4	1.6
Equity Earnings in ATC		18.5	16.3	19.6
Distributed ATC Earnings		(12.8)	(14.5)
Equity Investment Ending Balance		135.6	124.5	121.1
Balance Sheet Data [Abstract]
Current Assets		75.8	80.5
Non-Current Assets		4,312.9	3,957.6
Total Assets		4,388.7	4,038.1
Current Liabilities		495.1	330.3
Long-Term Debt		1,865.3	1,800.0
Other Non-Current Liabilities		271.5	245.0
Members' Equity		1,756.8	1,662.8
Total Liabilities and Members' Equity		4,388.7	4,038.1
Income Statement Data [Abstract]
Revenue		650.8	615.8	635.0
Operating Expense		322.5	319.3	307.4
Other Expense		95.5	96.1	88.9
Net Income		232.8	200.4	238.7
ALLETE's Equity in Net Income		$ 18.5	$ 16.3	$ 19.6
Authorized Return on Equity		10.32%			12.20%
Authorized Return on Equity, Including Incentive Adder		10.82%
ATC [Member] \| Sensitivity Analysis [Member]
Income Statement Data [Abstract]
Basis Point Reduction on Approved Rate of Return on Common Equity		50
ATC [Member] \| Sensitivity Analysis [Member] \| After-tax [Member]
Income Statement Data [Abstract]
Annual Effect on Future Equity Earnings in ATC		$ 0.5
ATC [Member] \| Subsequent Event [Member]
ALLETE's Investment in ATC [Roll Forward]
Cash Investments	$ 3.1

Acquisitions Acquisitions (Details)	12 Months Ended
Acquisitions Acquisitions (Details)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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 - Acquisition of Non-Controlling Interest (Details) - USD ($) $ in Millions		12 Months Ended
	Apr. 15, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Acquisition of Non-Controlling Interest [Line Items]
Payments to Acquire Additional Interest in Subsidiaries		$ 8.0	$ 0.0	$ 6.0
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

Oct. 11, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Water & Energy Systems Technology [Member]

$ 131.2

$ 130.6

$ 2.9

100.00%

Water & Energy Systems Technology of Nevada, Inc.

Total Consideration

$ 6.5

Payments Due in April 2018

5.9

0.6

0.1

1.1

Customer Relationships

^[1]

2.8

^[2]

3.9

0.1

8.0

0.2

1.2

1.4

6.6

$ 0.0

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

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, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 130.6

$ 131.2

$ 130.6

$ 2.9

^[1]

$ 5.6

$ 2.2

5.6

U.S. Water Services

Total Consideration

$ 202.3

Percent of Results of Operations Reflected in Income Statement

166.6

Contingent Consideration

$ 35.7

100.00%

100.00%

$ 0.9

Accounts Receivable

16.8

Inventories

^[2]

13.4

^[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

$ 2.9

$ 3.0

[1]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements 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, 2016

USD ($)

Dec. 31, 2014

USD ($)

$ 138.1

$ 113.8

130.6

131.2

$ 2.9

Chanarambie/Viking [Member]

23.3

$ 24.6

100.00%

Chanarambie/Viking

$ 48.0

97.5

Current Assets

$ 4.8

103.0

^[1]

1.0

108.8

^[2]

6.7

49.0

5.1

60.8

48.0

0.3

0.0

$ 5.9

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

$ 0.2

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, 2016

USD ($)

^[1]

$ 5.6

$ 2.2

Armenia Mountain [Member]

^[2]

8.1

$ 8.6

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

6.1

$ 0.0

$ 1.6

[1]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and collateral deposits required for U.S. Water Services’ standby letters of credit.
[2]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements 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, 2016

Dec. 31, 2015

Dec. 31, 2014

A and W Technologies [Member]

$ 131.2

$ 130.6

$ 2.9

100.00%

A and W Technologies, Inc.

Total Consideration

$ 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.

Acquisitions - ACE Wind (Details)
$ in Millions

12 Months Ended

Dec. 31, 2016

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

$ 113.8

$ 138.1

131.2

$ 2.9

130.6

Purchase of Non-Controlling Interest

24.6

$ 23.3

$ 6.7

$ 6.0

Lake Benton [Member]

Lake Benton

104

Storm Lake II [Member]

Storm Lake II

Condon [Member]

Condon

ACE Wind [Member]

Number of Wind Energy Facilities Acquired

$ 26.9

$ 3.8

14.3

156.9

^[1]

7.5

182.5

Long-Term Debt Due Within One Year

^[2]

15.2

2.2

Long-Term Debt

21.1

Other Non-Current Liabilities

99.4

10.6

Non-Controlling Interest

^[3]

7.1

Total Liabilities and Non-Controlling Interest Assumed

155.6

26.9

2.9

0.0

12.4

Purchase of Non-Controlling Interest

1.4

6.0

Gain or Loss Recognized in Net Income or Other Comprehensive Income

0.0

Armenia Mountain [Member] | ACE Wind [Member]

Purchase option

$ 0.3

[1]	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain, and goodwill of $2.9 million. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[2]	Current Liabilities included $12.4 million related to the current portion of PSAs.
[3]	The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method.

Acquisitions - Storm Lake I (Details)
$ in Millions

12 Months Ended

Dec. 31, 2014

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

$ 113.8

$ 138.1

^[1]

8.6

8.1

$ 24.6

$ 23.3

Storm Lake I [Member]

Storm Lake I

$ 15.1

108

$ 0.4

4.7

47.3

^[2]

11.4

63.8

^[3]

8.2

23.5

17.0

48.7

15.1

0.4

0.0

$ 7.5

[1]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and PSAs, and deposits from SWL&P customers in aid of future capital expenditures.
[2]	Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[3]	Current Liabilities included $7.5 million related to the current portion of PSAs.

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Goodwill [Roll Forward]

$ 130.6

$ 2.9

Acquired Goodwill

^[1]

3.9

127.7

Impairment Charge

^[2]

(3.3)

^[3]

0.0

$ 0.0

131.2

130.6

2.9

Goodwill [Roll Forward]

3.3

2.9

Acquired Goodwill

^[1]

0.0

0.4

Impairment Charge

(3.3)

^[3]

0.0

0.0

3.3

2.9

Goodwill [Roll Forward]

127.3

0.0

Acquired Goodwill

^[1]

3.9

127.3

Impairment Charge

0.0

^[3]

0.0

Definite-Lived Intangible Assets [Roll Forward]

$ 131.2

$ 127.3

$ 0.0

[1]	See Note 6. Acquisitions.
[2]	See Goodwill and Intangible Assets.
[3]	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 January 2014.

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 68.0

^[1]

2.8

Amortization

(5.2)

$ (4.0)

$ (0.1)

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

65.6

68.0

5.5

5.1

4.8

4.5

4.4

41.3

Intangible Assets [Abstract]

Total Intangible Assets

82.2

84.6

Total Intangible Assets, Additions

^[1]

2.8

Total Intangible Assets, Amortization

(5.2)

(4.0)

$ (0.1)

Accumulated Amortization

$ 9.3

4.1

Minimum [Member]

Definite-Lived Intangible Assets [Roll Forward]

Definite-Lived Intangible Assets [Roll Forward]

2 years

Maximum [Member]

Weighted Average [Member]

21 years

Definite-Lived Intangible Assets [Roll Forward]

Trademarks and Trade Names [Member]

20 years

Indefinite-Lived Intangible Assets [Roll Forward]

$ 16.6

^[1]

0.0

Customer Relationships [Member]

16.6

Definite-Lived Intangible Assets [Roll Forward]

60.8

^[1]

2.8

Amortization

(4.3)

$ 59.3

60.8

Total Intangible Assets, Amortization

21 years

Intangible Assets [Abstract]

$ (4.3)

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

^[2]

7.2

^[1],[2]

0.0

Amortization

^[2]

(0.9)

Total Intangible Assets, Amortization

^[2]

6.3

$ 7.2

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]

2 years

Definite-Lived Intangible Assets [Roll Forward]

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

12 years

Definite-Lived Intangible Assets [Roll Forward]

8 years

[1]	Additions resulting from the October 11, 2016, acquisition of WEST. (See Note 6. Acquisitions.)
[2]	Developed Technology and Other includes patents, non-compete agreements and land easements.

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Available-for-sale Securities

ALLETE Properties

^[1]

$ 31.7

$ 50.1

^[2]

18.8

18.5

1.3

2.0

Real Estate Sale Consideration [Abstract]

3.8

4.0

Total Other Investments

55.6

74.6

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

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

One Year or Less

$ 0.2

One Year to Less Than Three Years

3.2

Three Years to Less Than Five Years

5.0

Five or More Years

3.3

Impairment of Land Inventory

^[3]

$ 0.0

$ 36.3

$ 0.0

[1]	On September 22, 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, with the remaining purchase price to be paid under the terms of a finance receivable due over a five-year period which bears interest at market rates. The finance receivable is collateralized by the property sold.
[2]	As of December 31, 2016, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $3.2 million, in three years to less than five years was $5.0 million, and in five or more years was $3.3 million.
[3]	See Impairment of Long-Lived Assets.

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

$ 1.3

$ 2.0

Recurring Fair Value Measures [Member]

^[1]

25.0

36.6

Available-for-sale – Corporate and Governmental Debt Securities

7.1

^[2]

7.6

^[3]

11.7

^[2]

10.9

^[3]

1.3

^[2]

2.0

^[3]

20.1

20.5

16.0

^[4]

16.1

^[5]

25.0

^[4]

36.6

^[5]

41.0

52.7

(20.9)

(32.2)

Fair Value Hierarchy Transfers, All Levels

0.0

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

Available-for-sale – Corporate and Governmental Debt Securities

7.1

^[2]

7.6

^[3]

0.0

^[2]

0.0

^[3]

1.3

^[2]

2.0

^[3]

8.4

9.6

0.0

^[4]

0.0

^[5]

0.0

^[4]

0.0

^[5]

0.0

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

8.4

9.6

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[2]

0.0

^[3]

11.7

^[2]

10.9

^[3]

0.0

^[2]

0.0

^[3]

11.7

10.9

16.0

^[4]

16.1

^[5]

0.0

^[4]

0.0

^[5]

16.0

16.1

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

(4.3)

(5.2)

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]

25.0

^[4]

36.6

^[5]

25.0

36.6

(25.0)

(36.6)

36.6

0.0

Recurring Fair Value Measures [Member] | Level 3 [Member] | Recognition of U.S. Water Services Contingent Consideration [Member]

25.0

36.6

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

(35.7)

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

^[6]

(2.8)

(2.4)

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

0.8

0.1

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

$ 13.6

$ 1.4

[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.

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,569.1	$ 1,605.0
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,653.8	$ 1,676.0

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Equity Method Investment, Carrying Amount

$ 135.6

$ 124.5

131.2

130.6

$ 2.9

Intangible Assets, Carrying Amount

^[1]

3.3

^[2]

0.0

82.2

84.6

Intangible Assets, Indicators of Impairment

0.0

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

3,741.2

3,669.1

Taconite Harbor [Member]

Boswell Units 1 and 2 [Member]

90.0

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

30.0

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

131.2

127.3

0.0

0.0

^[2]

0.0

12.6

12.2

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

0.0

3.3

2.9

3.3

^[2]

0.0

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

532.3

447.3

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

Equity Method Investment, Indicators of Impairment

0.0

Intangible Assets, Carrying Amount

82.2

84.6

Intangible Assets, Indicators of Impairment

0.0

Property, Plant and Equipment, 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]

131.2

130.6

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member] | ALLETE Clean Energy [Member]

0.0

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

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

$ 3.3

ATC [Member]

Ownership Percentage

8.00%

Equity Method Investment, Carrying Amount

$ 135.6

124.5

$ 121.1

ATC [Member] | 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]

Ownership Percentage

8.00%

Equity Method Investment, Carrying Amount

$ 135.6

$ 124.5

Equity Method Investment, Indicators of Impairment

$ 0.0

[1]

See Goodwill and Intangible Assets.

[2]

Short-Term and Long-Term Debt - Short-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Short-term Debt Outstanding	$ 187.7	$ 37.3
Short-Term Debt - Unamortized Debt Issuance Costs	0.6
Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	409.0	408.4
Standby Letters of Credit Outstanding	11.1	12.4
Draws Outstanding	$ 0.0	$ 1.6

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.

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

Short-Term and Long-Term Debt - Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-Term Debt	$ 1,370.4	$ 1,556.7
Long-Term Debt - Unamortized Debt Issuance Costs	10.4
Long-term Debt Maturities [Abstract]
Long-Term Debt Maturing in 2017	188.3
Long-Term Debt Maturing in 2018	63.1
Long-Term Debt Maturing in 2019	55.2
Long-Term Debt Maturing in 2020	101.2
Long-Term Debt Maturing in 2021	96.4
Long-Term Debt Maturing Thereafter	1,064.9
Camp Ripley Financing [Member]
Long-term Debt Maturities [Abstract]
Annual Financing Payment	$ 1.4
Financing Renewal Term	2 years
Purchase Option	$ 4.0
Senior Unsecured Notes 3.11% Due 2027 [Member]
Long-term Debt Maturities [Abstract]
Expected Proceeds from Future Issuance of Senior Unsecured Notes	$ 80.0
Expected Future Interest Rate	3.11%

Short-Term and Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt	$ 1,569.1	$ 1,605.0
Unamortized Debt Issuance Costs	(11.0)	(12.6)
Total Long-Term Debt	1,558.1	1,592.4
Less: Due Within One Year	187.7	35.7
Net Long-Term Debt	1,370.4	1,556.7
First Mortgage Bonds - 7.70% Series Due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 0.0	20.0
Interest Rate	7.70%
First Mortgage Bonds - 1.83% Series Due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50.0	50.0
Interest Rate	1.83%
First Mortgage Bonds - 8.17% Series Due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 42.0	42.0
Interest Rate	8.17%
First Mortgage Bonds - 5.28% Series Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 35.0	35.0
Interest Rate	5.28%
First Mortgage Bonds - 2.80% Series Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 40.0	40.0
Interest Rate	2.80%
First Mortgage Bonds - 4.85% Series Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 15.0	15.0
Interest Rate	4.85%
First Mortgage Bonds - 3.02% Series Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 60.0	60.0
Interest Rate	3.02%
First Mortgage Bonds - 3.40% Series Due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 75.0	75.0
Interest Rate	3.40%
First Mortgage Bonds - 6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 75.0	75.0
Interest Rate	6.02%
First Mortgage Bonds - 3.69% Series Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 60.0	60.0
Interest Rate	3.69%
First Mortgage Bonds - 4.90% Series Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 30.0	30.0
Interest Rate	4.90%
First Mortgage Bonds - 5.10% Series Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 30.0	30.0
Interest Rate	5.10%
First Mortgage Bonds - 3.20% Series Due 2026 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 75.0	75.0
Interest Rate	3.20%
First Mortgage Bonds - 5.99% Series Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 60.0	60.0
Interest Rate	5.99%
First Mortgage Bonds - 3.30% Series Due 2028 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 40.0	40.0
Interest Rate	3.30%
First Mortgage Bonds - 3.74% Series Due 2029 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50.0	50.0
Interest Rate	3.74%
First Mortgage Bonds - 3.86% Series Due 2030 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 60.0	60.0
Interest Rate	3.86%
First Mortgage Bonds - 5.69% Series Due 2036 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50.0	50.0
Interest Rate	5.69%
First Mortgage Bonds - 6.00% Series Due 2040 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 35.0	35.0
Interest Rate	6.00%
First Mortgage Bonds - 5.82% Series Due 2040 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 45.0	45.0
Interest Rate	5.82%
First Mortgage Bonds - 4.08% Series Due 2042 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 85.0	85.0
Interest Rate	4.08%
First Mortgage Bonds - 4.21% Series Due 2043 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 60.0	60.0
Interest Rate	4.21%
First Mortgage Bonds - 4.95% Series Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 40.0	40.0
Interest Rate	4.95%
First Mortgage Bonds - 5.05% Series Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 40.0	40.0
Interest Rate	5.05%
First Mortgage Bonds - 4.39% Series Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50.0	50.0
Interest Rate	4.39%
Unsecured Term Loan Variable Rate Due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 125.0	125.0
Senior Unsecured Notes 5.99% Due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50.0	50.0
Interest Rate	5.99%
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 13.5	13.5
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	27.8	27.8
Armenia Mountain Senior Secured Notes 3.26% Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 74.6	83.3
Interest Rate	3.26%
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 15.0	15.0
Interest Rate	4.15%
Other Long-Term Debt, 3.11% – 6.20% Due 2017 – 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 61.2	$ 68.4
Minimum [Member] \| Other Long-Term Debt, 3.11% – 6.20% Due 2017 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate	3.11%
Maximum [Member] \| Other Long-Term Debt, 3.11% – 6.20% Due 2017 – 2037 [Member]
Debt Instrument [Line Items]
Interest Rate	6.20%

Short-Term and Long-Term Debt - Financial Covenants (Details)	12 Months Ended
	Dec. 31, 2016
Financial Covenants [Abstract]
Allowed Indebtedness to Total Capitalization Ratio	0.65
Actual Indebtedness to Total Capitalization Ratio	0.45
Compliance with Financial Covenants	ALLETE was in compliance with its financial covenants.

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

12 Months Ended

Dec. 31, 2016

USD ($)

Minimum Lease Payments in 2017

$ 13.7

Minimum Lease Payments in 2018

12.0

Minimum Lease Payments in 2019

10.7

Minimum Lease Payments in 2020

7.5

Minimum Lease Payments in 2021

5.9

Minimum Lease Payments Thereafter

18.3

Coal Supply and Transportation Agreements [Member]

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

Minimum Annual Payment Obligation in 2017

27.9

Minimum Annual Payment Obligation in 2018

27.0

Minimum Annual Payment Obligation in 2019

1.8

Minimum Annual Payment Obligation in 2020

0.0

Minimum Annual Payment Obligation in 2021

0.0

Minimum Annual Payment Obligation Thereafter

0.0

Power Purchase Agreement [Member]

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

Minimum Annual Payment Obligation in 2017

98.0

^[1]

Minimum Annual Payment Obligation in 2018

102.9

^[1]

Minimum Annual Payment Obligation in 2019

105.5

^[1]

Minimum Annual Payment Obligation in 2020

113.4

^[1]

Minimum Annual Payment Obligation in 2021

143.3

^[1]

Minimum Annual Payment Obligation Thereafter

$ 1,803.9

^[1]

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

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

Output Being Purchased (MW) | MW

133

[1]

Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only, and the 133 MW agreement with Manitoba Hydro commencing in 2020, as our obligation under this contract is subject to construction of additional transmission capacity. Also excludes Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered.

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Leasing Agreements [Line Items]
Minimum Lease Payments in 2017	$ 13.7
Minimum Lease Payments in 2018	12.0
Minimum Lease Payments in 2019	10.7
Minimum Lease Payments in 2020	7.5
Minimum Lease Payments in 2021	5.9
Minimum Lease Payments Thereafter	18.3
Total Lease Expense	17.1	$ 17.3	$ 14.8
BNI Energy Dragline [Member]
Leasing Agreements [Line Items]
Minimum Lease Payments in 2017	2.8
Minimum Lease Payments in 2018	2.8
Minimum Lease Payments in 2019	2.8
Minimum Lease Payments in 2020	2.8
Minimum Lease Payments in 2021	2.8
Minimum Lease Payments Thereafter	16.8
Termination Fee	$ 3.0

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) MWh in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) MWh MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Square Butte PPA (expires December 2026) [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Output Entitlement	50.00%
Output Being Purchased (MW)	227.5
Square Butte [Member] \| Square Butte PPA (expires December 2026) [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Total Debt Outstanding \| $	$ 327.7
PPA Counterparty Annual Debt Service \| $	45.0
Cost of Purchased Power \| $	73.3	$ 77.8	$ 70.1
Pro Rata Share of PPA Counterparty Interest Expense \| $	$ 9.6	$ 10.1	$ 10.5
Square Butte [Member] \| Square Butte PPA (expires December 2026) [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)	455
Minnkota Power [Member] \| Square Butte PPA (expires December 2026) [Member] \| Minnkota Power PSA (expires December 2026) [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Output Entitlement	28.00%	28.00%	23.00%
Minnkota Power [Member] \| Minnkota Power PPA (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Great River Energy [Member] \| Great River Energy Capacity and Energy PPA (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Great River Energy [Member] \| Great River Energy Capacity PPA Beginning June 2016 (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Great River Energy [Member] \| Great River Energy Capacity PPA Beginning June 2017 (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires April 2022) [Member] \| Minimum [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh) \| MWh	1
Manitoba Hydro [Member] \| Manitoba Hydro PPA Beginning June 2015 (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro [Member] \| Manitoba Hydro PPA Beginning June 2017 (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires May 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires 2040) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	133
Contract Term (Years)	20 years
Oliver Wind [Member] \| Oliver Wind I PPA (expires December 2031) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Oliver Wind [Member] \| Oliver Wind II PPA (expires December 2032) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Shell Energy [Member] \| Shell Energy PPA (expires December 2019) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
TransAlta [Member] \| TransAlta Off-Peak Hours PPA (expires December 2019) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
TransAlta [Member] \| TransAlta On-Peak Hours PPA (expire December 2019) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	100
Basin [Member] \| Basin PSA (expires April 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	100
Basin [Member] \| Basin PSA (expires June 2018) [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	100
Silver Bay Power [Member] \| Silver Bay Power Self-Generation [Member]
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)	90
Silver Bay Power [Member] \| Silver Bay Power PSA through 2031 (Years 2016-2019) [Member] \| Minimum [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	50

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) kV Miles MW
Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	$ 560
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Total Project Cost in the U.S.	$ 710
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires May 2035) [Member]
Transmission [Line Items]
Output Being Purchased (MW) \| MW	250

Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) MW
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
SO2 and 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, 2016	Dec. 31, 2015
ALLETE Clean Energy [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 14.6
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	5.4
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	72.00%	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	92.00%	92.00%
Annual Assessment	$ 2.1

Common Stock and Earnings Per Share - Summary of Common Stock (Details) - USD ($) shares in Thousands, $ in Millions		12 Months Ended
	Jan. 17, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of Common Stock [Line Items]
Balance, Shares		49,600	49,100
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)		$ (6.0)
Contributions to Pension, Equity		$ 0.0	$ 0.0	$ 19.5
Common Stock [Member]
Summary of Common Stock [Line Items]
Balance, Shares		49,560	49,075	45,929	41,401
Balance, Equity		$ 1,295.3	$ 1,271.4	$ 1,107.6	$ 885.2
Employee Stock Purchase Program, Shares		16	18	18
Employee Stock Purchase Program, Equity		$ 0.9	$ 0.9	$ 0.8
Invest Direct, Shares		344	383	378
Invest Direct, Equity		$ 20.0	$ 19.0	$ 18.9
Options and Stock Awards, Shares		65	43	78
Options and Stock Awards, Equity		$ 3.7	$ 8.6	$ 8.0
Contributions to RSOP, Shares		60
Contributions to RSOP, Equity		$ 3.3
Equity Issuance Program, Shares		130	1,289	1,851
Equity Issuance Program, Equity		$ 8.0	$ 69.9	$ 90.0
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)
Forward Sale Agreement and Issuance, Shares			1,413	1,807
Forward Sales Agreement and Issuance, Equity			$ 65.4	$ 85.2
Contributions to Pension, Shares		0	0	396
Contributions to Pension, Equity				$ 19.5
Equity Issuance Program Shares Authorized		13,600
Equity Issuance Program Shares Available for Issuance		3,900
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share		0	0	0
Common Stock [Member] \| Subsequent Event [Member]
Summary of Common Stock [Line Items]
Contributions to Pension, Shares	200
Contributions to Pension, Equity	$ 13.5

Common Stock and Earnings Per Share - Forward Sale Agreement and Issuance of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Feb. 04, 2015	Sep. 05, 2014	Mar. 04, 2014	Feb. 26, 2014	Dec. 31, 2016	Dec. 31, 2015
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares Issued					49.6	49.1
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
Option to Purchase Additional Shares [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares Issued			0.4
Proceeds from Issuance of Common Stock			$ 20.2

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 44.3	$ 40.3	$ 24.8	$ 45.9	$ 18.3	$ 60.4	$ 22.5	$ 39.9	$ 155.3	$ 141.1	$ 124.8
Average Common Shares									49.3	48.3	42.9
Earnings Per Share	$ 0.89	$ 0.82	$ 0.50	$ 0.93	$ 0.37	$ 1.24	$ 0.46	$ 0.85	$ 3.15	$ 2.92	$ 2.91
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE									$ 155.3	$ 141.1	$ 124.8
Average Common Shares									49.5	48.4	43.1
Earnings Per Share	$ 0.89	$ 0.81	$ 0.50	$ 0.93	$ 0.37	$ 1.23	$ 0.46	$ 0.85	$ 3.14	$ 2.92	$ 2.90
Dilutive Securities (Shares)									0.2	0.1	0.2

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Current Tax Expense [Abstract]

Federal

^[1]

$ 0.0

$ 1.1

State

^[1]

0.4

0.2

2.9

Total Current Tax Expense

0.4

0.2

4.0

Deferred Tax Expense [Abstract]

Federal

12.0

19.4

25.3

State

8.1

6.5

8.2

Investment Tax Credit Amortization

(0.7)

(0.8)

Total Deferred Tax Expense

19.4

25.1

32.7

Total Income Tax Expense

$ 19.8

$ 25.3

$ 36.7

[1]

Income Tax Expense - Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Abstract]
Income Before Non-Controlling Interest and Income Taxes	$ 175.6	$ 166.8	$ 162.2
Statutory Federal Income Tax Rate	35.00%	35.00%	35.00%
Income Taxes Computed at 35 Percent Statutory Federal Rate	$ 61.5	$ 58.4	$ 56.8
Increase (Decrease) in Tax Due to: [Abstract]
State Income Taxes – Net of Federal Income Tax Benefit	5.6	4.4	7.2
Regulatory Differences for Utility Plant	(0.1)	(0.6)	(3.5)
Production Tax Credits	(41.5)	(37.0)	(23.7)
Change in Fair Value of Contingent Consideration	(3.8)	0.0	0.0
Other	(1.9)	0.1	(0.1)
Total Income Tax Expense	$ 19.8	$ 25.3	$ 36.7
Effective Tax Rate	11.30%	15.20%	22.60%

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

Dec. 31, 2016

Dec. 31, 2015

Deferred Tax Assets [Abstract]

Employee Benefits and Compensation

$ 104.6

$ 105.4

Property Related

117.8

126.6

NOL Carryforwards

185.6

186.4

Tax Credit Carryforwards

227.4

164.8

Power Sales Agreements

59.3

73.0

Gross Deferred Tax Assets

46.9

21.8

741.6

678.0

Deferred Tax Asset Valuation Allowance

(43.0)

(31.6)

Total Deferred Tax Assets

698.6

646.4

Deferred Tax Liabilities [Abstract]

Property Related

1,094.7

1,053.0

Regulatory Asset for Benefit Obligations

91.9

89.4

Unamortized Investment Tax Credits

33.3

26.0

Partnership Basis Differences

50.9

47.8

Total Deferred Tax Liabilities

11.9

10.0

1,282.7

1,226.2

Net Deferred Income Taxes

^[1]

$ 584.1

$ 579.8

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

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

Dec. 31, 2016

Dec. 31, 2015

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforwards

^[1]

$ 485.3

$ 493.0

Tax Credit Carryforwards

163.7

113.6

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]

294.4

228.6

Tax Credit Carryforwards

^[2]

21.0

20.0

Tax Credit Carryforwards, Valuation Allowance

$ 42.7

$ 31.2

[1]	Pre-tax amounts.
[2]	Net of a $42.7 million valuation allowance as of December 31, 2016 ($31.2 million as of December 31, 2015).

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 2.4	$ 2.0	$ 1.2
Additions for Tax Positions Related to the Current Year	0.1	0.5	0.0
Additions for Tax Positions Related to Prior Years	0.2	0.7	1.0
Reduction for Tax Positions Related to Prior Years	(0.3)	(0.7)	0.0
Lapse of Statute	(0.4)	(0.1)	(0.2)
Balance as of December 31	2.0	2.4	2.0
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.6
Unrecognized Tax Benefits, Accrued Interest	0.0	0.0	0.0
Unrecognized Tax Benefits, Penalties	0.0	$ 0.0	$ 0.0
Material Changes to Unrecognized Tax Benefits Expected During Next 12 Months	$ 0.0

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

$ (24.5)

$ (21.1)

$ (17.1)

(4.1)

(4.6)

(5.3)

Amounts Reclassified from Accumulated Other Comprehensive Loss

0.4

1.2

1.3

(3.7)

(3.4)

(4.0)

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

(28.2)

(24.5)

(21.1)

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

(0.8)

(0.3)

(0.1)

0.0

(0.4)

(0.3)

Amounts Reclassified from Accumulated Other Comprehensive Loss

(0.2)

(0.1)

0.1

(0.2)

(0.5)

(0.2)

Defined Benefit Pension, Other Postretirement Items [Member]

(1.0)

(0.8)

(0.3)

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

^[1]

(23.7)

(20.7)

(16.7)

^[1]

(4.1)

(4.3)

(5.2)

Amounts Reclassified from Accumulated Other Comprehensive Loss

^[1]

0.6

1.3

1.2

^[1]

(3.5)

(3.0)

(4.0)

Gains (Loss) on Cash Flow Hedge [Member]

^[1]

(27.2)

(23.7)

(20.7)

Accumulated Other Comprehensive Loss [Roll Forward]

Other Comprehensive Income (Loss) Before Reclassifications

0.0

(0.1)

(0.3)

0.0

0.1

0.2

Amounts Reclassified from Accumulated Other Comprehensive Loss

0.0

0.0

0.1

0.2

$ 0.0

$ (0.1)

[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 ($) $ in Millions			1 Months Ended	12 Months Ended
	Jan. 17, 2017	Jan. 13, 2017	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions				$ 0.0	$ 0.0	$ 19.5
Defined Contribution RSOP, Employer Contributions				9.2	9.0	9.1
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions				6.3	0.0	0.0
Employer Contributions						19.5
Expected Employer Contributions in 2017				$ 0.0
Defined Benefit Plan, Plan Amendments				In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.
Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Employer Contributions in 2017				$ 0.0
Defined Benefit Plan, 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.
Subsequent Event [Member] \| Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions		$ 1.7	$ 15.2
Employer Contributions	$ 13.5
VEBA [Member] \| Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions				$ 0.0	0.0	0.0
Irrevocable Grantor Trust [Member] \| Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions				$ 0.0	$ 0.0	$ 0.0

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ (210.9)

$ (206.8)

Other Investments

55.6

74.6

Accumulated Benefit Obligation

698.8

665.0

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

709.8

714.5

Service Cost

8.1

10.1

$ 8.3

Interest Cost

33.2

29.9

29.8

Actuarial (Gain) Loss

12.4

(31.2)

Participant Contributions

(44.5)

(40.2)

24.3

26.7

Obligation, End of Year

743.3

709.8

714.5

Fair Value, Beginning of Year

521.3

544.2

Actual Return on Plan Assets

48.8

(10.8)

Employer Contribution

^[1]

31.9

28.1

Funded Status, End of Year

(44.5)

(40.2)

Fair Value, End of Year

557.5

521.3

544.2

(185.8)

(188.5)

(1.4)

(1.3)

(184.4)

(187.2)

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

160.2

170.9

Service Cost

3.9

4.3

3.4

Interest Cost

7.4

7.2

7.3

Actuarial (Gain) Loss

11.9

(14.4)

Participant Contributions

(13.1)

(10.7)

3.1

2.9

Obligation, End of Year

173.4

160.2

170.9

Fair Value, Beginning of Year

153.4

163.2

Actual Return on Plan Assets

9.6

(3.5)

Employer Contribution

1.3

1.5

Participant Contributions

3.1

2.9

Funded Status, End of Year

(13.1)

(10.7)

Fair Value, End of Year

154.3

153.4

$ 163.2

(19.1)

(6.8)

Non-Current Assets

1.4

6.4

(1.1)

(1.0)

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

(19.4)

(12.2)

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Other Investments

$ 17.6

$ 17.4

[1]	Includes Participant Contributions noted above.

Pension and Other Postretirement Benefit Plans - Unrecognized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ (250.4)	$ (252.7)
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	19.8	6.5
Prior Service Credit	(4.7)	(7.6)
Total Unrecognized Cost (Credit)	$ 15.1	$ (1.1)

Pension and Other Postretirement Benefit Plans - Components of Net Periodic Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost	$ 8.1	$ 10.1	$ 8.3
Interest Cost	33.2	29.9	29.8
Expected Return on Plan Assets	(43.6)	(40.7)	(38.2)
Amortization of Loss	9.5	17.9	14.2
Amortization of Prior Service Cost (Credit)	0.0	0.2	0.3
Net Expense (Credit)	7.2	17.4	14.4
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service Cost	3.9	4.3	3.4
Interest Cost	7.4	7.2	7.3
Expected Return on Plan Assets	(11.2)	(10.9)	(10.3)
Amortization of Loss	0.2	0.4	0.5
Amortization of Prior Service Cost (Credit)	(2.9)	(3.0)	(2.5)
Net Expense (Credit)	$ (2.6)	$ (2.0)	$ (1.6)

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, 2016	Dec. 31, 2015
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 7.2	$ 20.2
Amortization of Prior Service (Cost) Credit	0.0	(0.2)
Amortization of Loss	(9.5)	(17.9)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	(2.3)	2.1
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	13.5	0.0
Amortization of Prior Service (Cost) Credit	2.9	3.0
Amortization of Loss	(0.2)	(0.4)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$ 16.2	$ 2.6

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, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 743.3	$ 709.8
Accumulated Benefit Obligation	698.8	665.0
Fair Value of Plan Assets	$ 557.5	$ 521.3

Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2016 USD ($)
Pension [Member]
Estimated Future Benefit Payments [Abstract]
2017	$ 45.0
2018	45.2
2019	45.4
2020	45.5
2021	45.8
Years 2022 - 2026	231.0
Postretirement Health and Life [Member]
Estimated Future Benefit Payments [Abstract]
2017	9.3
2018	9.4
2019	9.7
2020	9.9
2021	10.0
Years 2022 - 2026	$ 51.4

Pension and Other Postretirement Benefit Plans - Costs Recorded in Regulatory Long-Term Assets or Liabilities and AOCI Expected to be Recognized as a Component of Net Pension and Postretirement Benefit Costs in the Next Fiscal Year (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 9.9
Prior Service Credit	0.0
Total Cost (Credit)	9.9
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	0.3
Prior Service Credit	(2.0)
Total Cost (Credit)	$ (1.7)

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

Dec. 31, 2014

Minimum [Member]

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

4.72%

4.30%

4.93%

Maximum [Member]

4.73%

4.33%

4.96%

Assumptions Used to Determine Benefit Obligation [Abstract]

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

4.53%

4.72%

Pension [Member] | Minimum [Member]

^[1]

8.00%

Assumptions Used to Determine Benefit Obligation [Abstract]

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

3.70%

Pension [Member] | Maximum [Member]

3.70%

Assumptions Used to Determine Benefit Obligation [Abstract]

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

4.30%

4.30%

Assumptions Used to Determine Benefit Obligation [Abstract]

Year Ultimate Trend Rate Effective

4.57%

4.73%

Health Care Trend Rates [Abstract]

Trend Rate

6.50%

Ultimate Trend Rate

4.50%

5.00%

2038

2022

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

Health Care Trend Rates [Abstract]

Trend Rate

5.00%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

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

^[1]

6.40%

Health Care Trend Rates [Abstract]

Trend Rate

7.00%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Subsequent Event [Member] | Pension [Member]

^[1]

8.00%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

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

7.50%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

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

6.00%

Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

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

7.50%

[1]	The expected long-term rates of return used to determine net periodic benefit expense for 2017 have been reduced to 7.50 percent for pension expense and 6.00 percent to 7.50 percent for postretirement health and life expense.

Pension and Other Postretirement Benefit Plans - Sensitivity of a One Percent Change in Health Care Trend Rates (Details) - Postretirement Health and Life [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 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	$ 20.1
Effect of One Percent Increase on Postretirement Health and Life Obligation	1.8
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(16.7)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (1.4)

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

12 Months Ended

Jan. 17, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Employer Contributions

$ 0.0

$ 19.5

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

Employer Stock Included in Equity Securities (Shares)

100.00%

0.0

Employer Contributions

$ 19.5

Pension [Member] | Equity Securities [Member]

100.00%

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

49.00%

47.00%

Pension [Member] | Debt Securities [Member]

56.00%

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

39.00%

Pension [Member] | Private Equity [Member]

35.00%

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

Pension [Member] | Real Estate [Member]

7.00%

8.00%

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

5.00%

6.00%

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]

60.00%

57.00%

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

^[2]

60.00%

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

^[1]

34.00%

35.00%

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]

6.00%

8.00%

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

^[1]

0.00%

Subsequent Event [Member] | Pension [Member]

^[2]

3.00%

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

Employer Contributions (Shares)

0.2

Employer Contributions

$ 13.5

[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, 2016	Dec. 31, 2015
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 43.3	$ 43.3
Actual Return on Plan Assets	5.0	2.6
Purchases, Sales, and Settlements – Net	(7.7)	(2.6)
Ending Balance	40.6	43.3
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	28.9	28.9
Actual Return on Plan Assets	2.3	2.9
Purchases, Sales, and Settlements – Net	(5.6)	(2.9)
Ending Balance	25.6	28.9
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	12.0	12.9
Actual Return on Plan Assets	1.4	1.2
Purchases, Sales, and Settlements – Net	(3.9)	(2.1)
Ending Balance	$ 9.5	$ 12.0

Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Stock Ownership Plan [Abstract]
ESOP Employer Loan	In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our common stock. The note was refinanced in 2006 at 6 percent and subsequently matured in December 2015.
ESOP Compensation Expense	$ 9.2	$ 9.0	$ 9.1
ESOP Shares, Allocated	1.6	1.8	1.9
ESOP Shares, Unallocated	0.0	0.0	0.3
ESOP Shares, Total	1.6	1.8	2.2
ESOP Shares, Fair Value of Unallocated Shares	$ 0.0	$ 0.0	$ 13.2

Employee Stock and Incentive Plans - Stock-Based Compensation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2016 shares
Non-Qualified Stock Options [Member]
Stock-based Compensation [Line Items]
Requisite Service Period (Years)	1 year
Annual Vesting Percentage	33.33%
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 2.6	$ 2.6	$ 2.3
Income Tax Benefit	1.1	1.1	1.0
Capitalized Share-Based Compensation Costs	0.0	0.0	0.0
Performance Shares [Member]
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	1.8	1.8	1.6
Unrecognized Compensation Cost	$ 2.3
Weighted-Average Period for Recognition (Years/Months)	1 year 8 months
Restricted Stock Units [Member]
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 0.8	$ 0.8	$ 0.7
Unrecognized Compensation Cost	$ 1.0
Weighted-Average Period for Recognition (Years/Months)	1 year 7 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, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2008

Number of Options [Roll Forward]

Outstanding as of January 1

39,654

66,279

108,299

^[1]

Exercised

(35,297)

(24,456)

(42,020)

Outstanding as of December 31

(2,169)

4,357

39,654

66,279

Exercisable as of December 31

4,357

39,654

66,279

Weighted-Average Exercise Price [Abstract]

Outstanding as of January 1

$ 44.39

$ 44.10

^[1]

0.00

Exercised

44.89

44.52

43.65

Outstanding as of December 31

0.00

42.93

0.00

40.29

44.39

Exercisable as of December 31

$ 40.29

$ 44.39

Weighted-Average Grant Date Intrinsic Value

$ 6.18

Cash Received from Non-Qualified Stock Options Exercised

$ 1.6

Total Intrinsic Value of Options Exercised

$ 0.5

$ 0.2

$ 0.4

[1]	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Employee Stock and Incentive Plans - Non-Qualified Stock Options, Range of Exercise Price (Details) - Non-Qualified Stock Options [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) $ / shares shares
$39.10 [Member]
Range of Exercise Price [Line Items]
Lower Range Limit	$ 39.10
Upper Range Limit	$ 39.10
Options Outstanding and Exercisable [Abstract]
Number Outstanding (Shares) \| shares	3,816
Number Exercisable (Shares) \| shares	3,816
Outstanding - Weighted Average Remaining Contractual Life (Years)	1 year 1 month
Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 1 month
Outstanding - Weighted Average Exercise Price	$ 39.10
Exercisable - Weighted Average Exercise Price	$ 39.10
Outstanding - Aggregate Intrinsic Value (Millions) \| $	$ 0.1
Exercisable - Aggregate Intrinsic Value (Millions) \| $	$ 0.1
$48.65 [Member]
Range of Exercise Price [Line Items]
Lower Range Limit	$ 48.65
Upper Range Limit	$ 48.65
Options Outstanding and Exercisable [Abstract]
Number Outstanding (Shares) \| shares	541
Number Exercisable (Shares) \| shares	541
Outstanding - Weighted Average Remaining Contractual Life (Years)	1 month
Exercisable - Weighted Average Remaining Contractual Life (Years)	1 month
Outstanding - Weighted Average Exercise Price	$ 48.65
Exercisable - Weighted Average Exercise Price	$ 48.65
Outstanding - Aggregate Intrinsic Value (Millions) \| $	$ 0.0
Exercisable - Aggregate Intrinsic Value (Millions) \| $	$ 0.0

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, 2017

Jan. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Performance Shares [Member]

127,580

119,540

119,635

114,765

^[1]

57,189

43,583

47,992

(36,515)

Unearned Grant Award

(42,126)

(36,670)

(7,023)

(7,008)

(6,607)

Performance Period (Years)

127,580

119,540

119,635

3 years

Weighted-Average Grant Date Fair Value [Abstract]

$ 52.56

$ 52.72

$ 48.26

$ 47.02

^[1]

52.43

58.95

46.47

0.00

42.01

Unearned Grant Award

52.70

45.41

0.00

53.45

53.49

48.29

Restricted Stock Units [Member]

$ 52.56

$ 52.72

$ 48.26

54,728

57,694

53,888

55,982

^[2]

20,351

26,702

19,645

(19,661)

(19,464)

(18,860)

(3,656)

(3,432)

(2,879)

Performance Period (Years)

54,728

57,694

53,888

3 years

Weighted-Average Grant Date Fair Value [Abstract]

$ 51.79

$ 49.86

$ 44.47

$ 40.85

^[2]

50.25

54.81

48.44

44.33

41.44

37.64

52.87

51.52

45.92

Subsequent Event [Member] | Performance Shares [Member]

$ 51.79

$ 49.86

$ 44.47

41,755

Performance Period (Years)

3 years

Granted, Grant Date Fair Value

$ 2.6

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

17,639

Granted, Grant Date Fair Value

(14,794)

$ 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, 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, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

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

Number of Reportable Segments

$ 341.5

$ 349.6

$ 314.8

$ 333.8

$ 380.6

$ 462.5

$ 323.3

$ 320.0

$ 1,339.7

$ 1,486.4

$ 1,136.8

44.3

$ 40.3

$ 24.8

$ 45.9

18.3

$ 60.4

$ 22.5

$ 39.9

155.3

141.1

124.8

Operating Expenses – Other

195.8

170.0

135.7

(10.3)

(36.3)

0.0

70.3

64.9

54.8

Equity Earnings in ATC

18.5

16.3

19.6

19.8

25.3

36.7

^[1]

4,906.4

4,894.5

4,906.4

4,894.5

Regulated Operations [Member]

$ 247.8

251.8

Number of Operating Segments

$ 1,000.7

991.2

1,003.5

135.5

131.6

^[2]

123.0

154.3

135.1

118.0

52.1

53.9

^[2]

49.2

Equity Earnings in ATC

18.5

16.3

19.6

5.9

24.4

39.0

^[1]

3,853.4

3,853.1

3,853.4

3,853.1

121.8

224.4

80.5

262.1

^[3]

33.2

13.4

29.9

3.3

Operating Expenses – Other

22.3

18.7

10.1

^[4]

(3.3)

0.0

5.8

3.3

0.8

8.1

21.0

2.3

^[1]

566.0

501.5

566.0

501.5

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

106.9

8.6

197.7

137.5

119.8

0.0

1.5

0.9

0.0

8.9

7.3

0.0

1.7

1.4

0.0

1.4

0.9

0.0

$ 264.1

258.3

264.1

258.3

Corporate and Other [Member]

$ 3.7

2.9

Number of Operating Segments

Land in Minnesota (Acres) | a

5,000

$ 121.0

113.3

100.1

^[2]

4.9

(21.3)

(1.5)

Operating Expenses – Other

10.3

8.9

7.6

^[4]

13.6

(36.3)

0.0

14.5

8.6

^[2]

7.1

4.4

(21.0)

(4.6)

$ 222.9

$ 281.6

222.9

281.6

15.4

15.9

Eliminations [Member]