Document and Entity Information Document - USD ($)	12 Months Ended
Document and Entity Information Document - USD ($)	Dec. 31, 2015	Feb. 01, 2016	Jun. 30, 2015
Document Information [Line Items]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,256,186,129
Entity Common Stock, Shares Outstanding		49,111,849
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents	$ 97.0	$ 145.8
Accounts Receivable (Less Allowance of $1.0 and $1.1)	121.2	103.0
Inventories	117.1	80.5
Prepayments and Other	35.7	82.0
Deferred Income Taxes	0.0	7.5
Total Current Assets	371.0	418.8
Property, Plant and Equipment – Net	3,669.1	3,284.8
Regulatory Assets	372.0	357.3
Investment in ATC	124.5	121.1
Other Investments	74.6	114.4
Goodwill and Intangible Assets – Net	215.2	4.8
Other Non-Current Assets	80.7	59.6
Total Assets	4,907.1	4,360.8
Current Liabilities [Abstract]
Accounts Payable	88.8	134.1
Accrued Taxes	44.0	38.7
Accrued Interest	18.6	18.0
Long-Term Debt Due Within One Year	36.3	100.7
Notes Payable	1.6	3.7
Other	86.1	120.8
Total Current Liabilities	275.4	416.0
Long-Term Debt	1,568.7	1,272.8
Deferred Income Taxes	579.8	510.7
Regulatory Liabilities	105.0	94.2
Defined Benefit Pension and Other Postretirement Benefit Plans	206.8	190.9
Other Non-Current Liabilities	349.0	265.0
Total Liabilities	$ 3,084.7	$ 2,749.6
Commitments, Guarantees and Contingencies (Note 12)
ALLETE's Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 49.1 and 45.9 Shares Outstanding	$ 1,271.4	$ 1,107.6
Unearned ESOP Shares	0.0	(7.2)
Accumulated Other Comprehensive Loss	(24.5)	(21.1)
Retained Earnings	573.3	530.1
Total ALLETE Equity	1,820.2	1,609.4
Non-Controlling Interest in Subsidiaries	2.2	1.8
Total Equity	1,822.4	1,611.2
Total Liabilities and Equity	$ 4,907.1	$ 4,360.8

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.0	$ 1.1
Common Stock [Abstract]
Common Stock, Par Value Per Share	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	49.1	45.9

Consilidated Statement of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Operating Revenue	$ 1,486.4	$ 1,136.8	$ 1,018.4
Operating Expenses [Abstract]
Fuel and Purchased Power	328.1	356.1	334.8
Transmission Services	54.1	45.6	32.3
Cost of Sales	302.3	77.9	71.2
Operating and Maintenance	333.5	287.1	267.7
Depreciation and Amortization	170.0	135.7	116.6
Taxes Other Than Income Taxes	51.4	45.6	41.7
Impairment of Real Estate	36.3	0.0	0.0
Total Operating Expenses	1,275.7	948.0	864.3
Operating Income	210.7	188.8	154.1
Other Income (Expense) [Abstract]
Interest Expense	(64.9)	(54.8)	(50.3)
Equity Earnings in ATC	16.3	19.6	20.3
Other	4.7	8.6	9.3
Total Other Expense	(43.9)	(26.6)	(20.7)
Income Before Non-Controlling Interest and Income Taxes	166.8	162.2	133.4
Income Tax Expense	25.3	36.7	28.7
Net Income	141.5	125.5	104.7
Less: Non-Controlling Interest in Subsidiaries	0.4	0.7	0.0
Net Income Attributable to ALLETE	$ 141.1	$ 124.8	$ 104.7
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	48.3	42.9	39.7
Diluted (Shares)	48.4	43.1	39.8
Basic Earnings Per Share of Common Stock	$ 2.92	$ 2.91	$ 2.64
Diluted Earnings Per Share of Common Stock	2.92	2.90	2.63
Dividends Per Share of Common Stock	$ 2.02	$ 1.96	$ 1.90

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net Income	$ 141.5	$ 125.5	$ 104.7
Other Comprehensive Income (Loss) [Abstract]
Unrealized Loss on Securities - Net of Income Taxes of $(0.3), $(0.2) and $–	(0.5)	(0.2)	0.0
Unrealized Gain on Derivatives - Net of Income Taxes of $0.1, $0.1 and $–	0.1	0.2	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Taxes of $(2.2), $(2.8) and $3.3	(3.0)	(4.0)	4.8
Total Other Comprehensive Income (Loss)	(3.4)	(4.0)	4.9
Total Comprehensive Income	138.1	121.5	109.6
Less: Non-Controlling Interest in Subsidiaries	0.4	0.7	0.0
Comprehensive Income Attributable to ALLETE	$ 137.7	$ 120.8	$ 109.6

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Unrealized Loss on Securities, Taxes	$ (0.3)	$ (0.2)	$ 0.0
Unrealized Gain on Derivatives, Taxes	0.1	0.1	0.0
Defined Benefit Pension and Other Postretirement Benefit Plans, Taxes	$ (2.2)	$ (2.8)	$ 3.3

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities
Net Income	$ 141.5	$ 125.5	$ 104.7
Allowance for Funds Used During Construction – Equity	(3.3)	(7.8)	(4.6)
Income from Equity Investments – Net of Dividends	(1.8)	(2.6)	(4.2)
Impairment of Real Estate	36.3	0.0	0.0
Gain on Sales of Investments and Property, Plant and Equipment	(0.2)	(0.2)	(2.6)
Depreciation Expense	165.9	135.7	116.6
Amortization of Power Purchase Agreements	(23.2)	(12.7)	0.0
Amortization of Other Intangible Assets and Other Assets	5.6	0.7	1.0
Deferred Income Tax Expense	25.1	32.7	28.6
Share-Based Compensation Expense	2.6	2.3	2.4
ESOP Compensation Expense	9.0	9.1	8.4
Defined Benefit Pension and Other Postretirement Benefit Expense	15.4	12.8	21.0
Bad Debt Expense	1.6	1.8	1.3
Changes in Operating Assets and Liabilities
Accounts Receivable	1.1	(3.5)	(8.6)
Inventories	(22.1)	(17.5)	10.5
Prepayments and Other	3.7	4.8	(1.4)
Accounts Payable	(19.3)	10.9	1.1
Other Current Liabilities	5.1	(3.5)	1.4
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans	0.0	0.0	(10.8)
Changes in Regulatory and Other Non-Current Assets	0.6	(21.3)	(18.3)
Changes in Regulatory and Other Non-Current Liabilities	(3.5)	2.6	(7.1)
Cash from Operating Activities	340.1	269.8	239.4
Investing Activities
Proceeds from Sale of Available-for-sale Securities	1.7	3.6	16.1
Payments for Purchase of Available-for-sale Securities	(2.3)	(5.0)	(4.7)
Acquisitions of Subsidiaries – Net of Cash Acquired	(333.3)	(60.3)	0.0
Investment in ATC	(1.6)	(3.9)	(3.1)
Changes to Other Investments	3.1	33.0	(12.3)
Additions to Property, Plant and Equipment	(286.8)	(572.8)	(328.5)
Construction Costs for Development Project	0.0	(25.7)	0.0
Cash in Escrow for Acquisition	0.0	5.4	(5.4)
Proceeds from Sale of Property, Plant and Equipment	0.4	0.0	1.3
Cash for Investing Activities	(618.8)	(625.7)	(336.6)
Financing Activities
Proceeds from Issuance of Common Stock	161.2	200.6	98.2
Proceeds from Issuance of Long-Term Debt	324.5	375.0	169.8
Changes in Restricted Cash	8.5	(1.8)	0.0
Changes in Notes Payable	(2.1)	3.7	0.0
Reductions of Long-Term Debt	(160.2)	(134.5)	(77.7)
Acquisition of Non-Controlling Interest	0.0	(6.0)	0.0
Construction Deposits Received for Development Project	0.0	54.3	0.0
Debt Issuance Costs	(4.1)	(3.1)	(1.4)
Dividends on Common Stock	(97.9)	(83.8)	(75.2)
Cash from Financing Activities	229.9	404.4	113.7
Change in Cash and Cash Equivalents	(48.8)	48.5	16.5
Cash and Cash Equivalents at Beginning of Period	145.8	97.3	80.8
Cash and Cash Equivalents at End of Period	$ 97.0	$ 145.8	$ 97.3

Consolidated Statement of Shareholders' Equity - USD ($) $ in Millions	Total	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Unearned ESOP Shares [Member]	Common Stock [Member]
Beginning Balance at Dec. 31, 2012	$ 1,201.0	$ 459.6	$ (22.0)	$ (21.3)	$ 784.7
Comprehensive Income
Net Income	104.7	104.7
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities – Net	0.0
Unrealized Gain on Derivatives – Net	0.1		0.1
Defined Benefit Pension and Other Postretirement Plans – Net	4.8		4.8
Total Comprehensive Income	109.6
Non-Controlling Interest in Subsidiaries	0.0
Comprehensive Income Attributable to ALLETE	109.6
Common Stock Issued – Net	100.5				100.5
Dividends Declared	(75.2)	(75.2)
ESOP Shares Earned	7.0			7.0
Ending Balance at Dec. 31, 2013	1,342.9	489.1	(17.1)	(14.3)	885.2
Comprehensive Income
Net Income	125.5	125.5
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities – Net	(0.2)		(0.2)
Unrealized Gain on Derivatives – Net	0.2		0.2
Defined Benefit Pension and Other Postretirement Plans – Net	(4.0)		(4.0)
Total Comprehensive Income	121.5
Non-Controlling Interest in Subsidiaries	(0.7)	(0.7)
Comprehensive Income Attributable to ALLETE	120.8
Common Stock Issued – Net	222.4				222.4
Dividends Declared	(83.8)	(83.8)
ESOP Shares Earned	7.1			7.1
Ending Balance at Dec. 31, 2014	1,609.4	530.1	(21.1)	(7.2)	1,107.6
Comprehensive Income
Net Income	141.5	141.5
Other Comprehensive Income – Net of Tax
Unrealized Loss on Securities – Net	(0.5)		(0.5)
Unrealized Gain on Derivatives – Net	0.1		0.1
Defined Benefit Pension and Other Postretirement Plans – Net	(3.0)		(3.0)
Total Comprehensive Income	138.1
Non-Controlling Interest in Subsidiaries	(0.4)	(0.4)
Comprehensive Income Attributable to ALLETE	137.7
Common Stock Issued – Net	163.8				163.8
Dividends Declared	(97.9)	(97.9)
ESOP Shares Earned	7.2			7.2
Ending Balance at Dec. 31, 2015	$ 1,820.2	$ 573.3	$ (24.5)	$ 0.0	$ 1,271.4

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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 accounting principles generally accepted in the United States of America. 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.

Reclassifications. As a result of recent acquisitions, certain financial statement captions have been added and we have reclassified certain prior-period amounts on our Consolidated Balance Sheet and Consolidated Statement of Income to conform to the presentation for the current period.

Consolidated Balance Sheet. In conformity with the current presentation of Goodwill and Intangible Assets - Net on the Consolidated Balance Sheet, we have reclassified our December 31, 2014, Consolidated Balance Sheet to include $1.6 million and $3.2 million of goodwill and intangible assets previously disclosed in Property, Plant and Equipment - Net and Other Non-Current Assets, respectively, under Goodwill and Intangible Assets - Net. There was no impact to Total Assets as a result of the reclassification.

Consolidated Statement of Income. In conformity with the current presentation of Cost of Sales on the Consolidated Statement of Income, we have reclassified $77.9 million from Operating and Maintenance expenses to Cost of Sales for the year ended December 31, 2014, and $71.2 million for the year ended December 31, 2013. Cost of Sales includes purchased gas at SWL&P, expenses incurred to deliver coal at BNI Energy, and the cost of land and other sales at ALLETE Properties. Cost of Sales also includes costs associated with the manufacture and delivery of inventories at U.S. Water Services which was acquired on February 10, 2015, and ALLETE Clean Energy’s cost to construct a wind energy facility that was sold to Montana-Dakota Utilities in 2015. (See Note 7. Acquisitions.) In addition to the presentation of Cost of Sales, we have created new captions on the Consolidated Statement of Income to provide additional detail for Transmission Services and Taxes Other than Income Taxes. Transmission Services are MISO-related costs incurred for the transmission of electricity. In conformity with the current presentation, we have reclassified from Operating and Maintenance expenses $45.6 million of Transmission Services and $45.6 million of Taxes Other than Income Taxes for the year ended December 31, 2014, and $32.3 million of Transmission Services and $41.7 million of Taxes Other than Income Taxes for the year ended December 31, 2013. There was no impact to Operating Income, Net Income, or Net Income Attributable to ALLETE as a result of these reclassifications.

Business Segments. During the year ended December 31, 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess, and allocate resources after our recent acquisitions. We now 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 was established in 2011, and 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 are under long-term power sales agreements. In addition, ALLETE Clean Energy constructed a 107 MW wind energy facility for sale to Montana-Dakota Utilities; construction and sale were completed in 2015.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

U.S. Water Services is our integrated water management company which was acquired on February 10, 2015.

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 2015, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 12. Commitments, Guarantees and Contingencies.)

ALLETE Properties represents our legacy Florida real estate investment. Our strategy for the assets had been to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. During the fourth quarter of 2015 the Company reevaluated its strategy related to the real estate assets of ALLETE Properties. The revised strategy incorporates the possibility of a bulk sale of its entire portfolio which, if consummated, is likely to result in sales proceeds below the book value of the real estate assets. ALLETE also continues to pursue sales of individual parcels over time. Proceeds from such a sale would be strategically deployed to support growth in our energy infrastructure and related services businesses. ALLETE will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions. (See Note 9. Investments.)

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

Supplemental Statement of Cash Flow Information



Consolidated Statement of Cash Flows
Year Ended December 31	2015		2014		2013
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$59.0		$51.3		$47.5
Cash Paid During the Period for Income Taxes		$0.4		$5.1		$0.5
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(40.6)			$21.7		$8.3
Capitalized Asset Retirement Costs		$12.4		$22.4	$(0.7)
AFUDC–Equity		$3.3		$7.8		$4.6
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	—			$19.5	—
Contingent Consideration		$35.7	—		—

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	2015		2014
Millions
Trade Accounts Receivable
Billed		$105.3		$85.5
Unbilled	16.9		18.6
Less: Allowance for Doubtful Accounts	1.0		1.1
Total Accounts Receivable		$121.2		$103.0

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 $9.2 million at December 31, 2015 ($14.7 million at December 31, 2014). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power’s taconite-producing Large Power Customers are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 7.7 percent of consolidated operating revenue in 2015 (11.9 percent in 2014; 12.0 percent in 2013).

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 9. Investments.)

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventories in our Regulated Operations and ALLETE Clean Energy segments are recorded on an average cost basis. Amounts removed from inventories in our U.S. Water Services and Corporate and Other segments are recorded on an average cost, first-in, first-out or specific identification basis.



Inventories
As of December 31	2015			2014
Millions
Fuel (a)		$58.1			$29.0
Materials and Supplies	49.1			51.5
Raw Materials	2.7			—
Finished Goods	7.5			—
Reserve for Obsolescence	(0.3		)	—
Total Inventories		$117.1			$80.5


(a)	Fuel consists primarily of coal inventory at Minnesota Power. During 2015, Minnesota Power increased its coal inventory to take advantage of favorable pricing.



Prepayments and Other Current Assets
As of December 31	2015		2014
Millions
Deferred Fuel Adjustment Clause		$10.6		$16.3
Construction Costs for Development Project (a)	—		48.2
Restricted Cash (b)	5.6		2.7
Other	19.5		14.8
Total Prepayments and Other Current Assets		$35.7		$82.0


(a)	Construction Costs for Development Project related to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)


(b)	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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the 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-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for the effects of certain types of regulation. 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 3. 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. Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to natural gas in 2015, which were actions included in Minnesota Power’s 2013 IRP approved by the MPUC in a November 2013 order. On September 1, 2015, Minnesota Power filed its 2015 IRP with the MPUC. The 2015 IRP contains the next steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016 and the ceasing of coal-fired operations at Taconite Harbor in 2020. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2, or the conversion of Laskin. In addition, we expect to be able to continue depreciating these assets over their established remaining useful lives; however we are unable to predict the impact of unanticipated regulatory outcomes resulting in changes to their established remaining useful lives. The remaining net book value for Taconite Harbor as of December 31, 2015 was approximately $100 million. We would seek recovery in a general rate case of additional depreciation expense as a result of material changes in useful lives.

Impairment of Long-Lived Assets. Land inventory is accounted for as held for use and is recorded at cost or estimated fair value. We review our long-lived assets, which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate 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, which may include a bulk sale of its entire portfolio, the sale of each individual land parcel, combining various parcels, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net cash flows on an undiscounted basis. 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, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel, may vary among each land parcel, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.

In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In response to market conditions and recent transaction activity, during the fourth quarter of 2015 the Company reevaluated its strategy related to the real estate assets of ALLETE Properties. The revised strategy incorporates the possibility of a bulk sale of its entire portfolio which, if consummated, is likely to result in sales proceeds below the book value of the real estate assets. ALLETE also continues to pursue sales of individual parcels over time. Proceeds from such a sale would be strategically deployed to support growth in our energy infrastructure and related services businesses. ALLETE will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.

In connection with implementing the revised strategy in 2015, management evaluated its impairment analysis for its real estate assets using updated assumptions to determine estimated future net cash flows on an undiscounted basis. Future net cash flows were adjusted to consider the possibility of a bulk sale of its entire portfolio, in addition to sales over time under the existing divestiture plan. 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets (Continued)

Based on the results of undiscounted cash flow analysis, the undiscounted future net cash flows were not adequate to recover the carrying value of the real estate assets totaling $83.3 million. Estimated fair value was derived from 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 at December 31, 2015.

If our real estate assets are sold differently than anticipated, the actual results could be materially different from our undiscounted future net cash flow analysis.

In 2014 and 2013, impairment analyses of estimated undiscounted future net cash flows were conducted based on the strategy existing at that time, 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 for the years ended December 31, 2014 and 2013.

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 18. Employee Stock and Incentive Plans.)

Goodwill and Intangible Assets.

Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. To align with the annual budgeting and forecasting process, 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. 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 estimated fair value is generally determined using a discounted cash flow analysis.

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 useful lives ranging from approximately 3 years to approximately 22 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.

Other Non-Current Assets. As of December 31, 2015, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $8.1 million related to collateral deposits required under ALLETE Clean Energy’s loan agreements ($5.3 million as of December 31, 2014).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Current Liabilities
As of December 31	2015		2014
Millions
Customer Deposits		$15.1		$19.7
Power Purchase Agreements (a)	23.3		19.4
Construction Deposits Received for Development Project (b)	—		54.3
Other (c)	47.7		27.4
Total Other Current Liabilities		$86.1		$120.8


(a)	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)


(b)	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)


(c)	Increase in 2015 includes customer refund liabilities of approximately $7 million, pending regulatory approval.



Other Non-Current Liabilities
As of December 31	2015		2014
Millions
Asset Retirement Obligation		$131.4		$109.2
Power Purchase Agreements (a)	138.1		110.7
Contingent Consideration (b)	36.6		—
Other	42.9		45.1
Total Other Non-Current Liabilities		$349.0		$265.0


(a)	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 7. Acquisitions and Note 10. 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 12. Commitments, Guarantees and Contingencies.)

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 energy and environmental expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause.

Revenue from our cost recovery riders (renewable resources, transmission 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 our Consolidated Statement of Income and Regulatory Assets on our Consolidated Balance Sheet until it is subsequently collected from customers.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition (Continued)

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 our Consolidated Statement of Income. The revenue and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.

ALLETE Clean Energy recognizes revenue from the sale of energy under long-term PPAs. 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 the wind energy facilities acquisitions in 2014 and 2015, ALLETE Clean Energy assumed various PPAs 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 2015, we recognized $23.2 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 ($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.

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 15. 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 involves 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 7. Acquisitions.)

New Accounting Standards.

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. In April 2014, the FASB issued an accounting standard update modifying the criteria for determining which disposals should be presented as discontinued operations and modifying the related disclosure requirements. Additionally, the new guidance requires that a business which qualifies as held for sale upon acquisition should be reported as discontinued operations. The new guidance was effective beginning in the first quarter of 2015, and will be applied prospectively to disposals and classifications of disposal groups as held for sale. The impact of this guidance on our consolidated financial position, results of operations or cash flows will be evaluated when future transactions arise.

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. This accounting guidance was to have been effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. On July 9, 2015, the FASB decided to defer the effective date of the standard by one year which will make the guidance effective for the Company beginning in the first quarter of 2018. Early adoption is permitted beginning in the first quarter of 2017 for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s Consolidated Financial Statements.

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. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The adoption of this update is not expected to 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.

Balance Sheet Classification of Deferred Taxes. In November 2015, the FASB issued an accounting standard to simplify the presentation of deferred income taxes. Under the new standard, both deferred tax liabilities and assets are required to be classified as noncurrent instead of separating deferred taxes into current and noncurrent amounts. This accounting guidance is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted. During the fourth quarter of 2015, we elected to prospectively adopt the new standard, reclassifying $39.4 million of current deferred income tax assets to noncurrent deferred income tax liabilities on our Consolidated Balance Sheet for 2015. Previously reported periods have not been adjusted. The adoption of this guidance had no impact on our Consolidated Statement of Income, Consolidated Statement of Comprehensive Income and Consolidated Statement of Cash Flows.

Business Segments

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

During the year ended December 31, 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess, and allocate resources after our recent acquisitions. We now present three reportable segments, Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. Prior period amounts have been revised to conform with the current business segment presentation.

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 acquiring or developing capital projects that create energy solutions by way of wind, solar, biomass, hydro, natural gas, shale resources, clean coal technology and other emerging energy innovations. U.S. Water Services is our integrated water management company which was acquired on February 10, 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 2. BUSINESS SEGMENTS (Continued)



Year Ended December 31	2015			2014			2013
Millions
Operating Revenue
Regulated Operations		$991.2			$1,003.5			$925.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	262.1			33.2			—
U.S. Water Services	119.8			—			—

Corporate and Other	113.3			100.1			92.9
Total Operating Revenue		$1,486.4			$1,136.8			$1,018.4
Net Income (Loss) Attributable to ALLETE
Regulated Operations (a)		$131.6			$123.0			$103.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	29.9			3.3			(3.4		)
U.S. Water Services	0.9			—			—

Corporate and Other (a)	(21.3		)	(1.5		)	4.5
Total Net Income Attributable to ALLETE		$141.1			$124.8			$104.7
Depreciation and Amortization
Regulated Operations		$135.1			$118.0			$110.2

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

Corporate and Other	8.9			7.6			6.4
Total Depreciation and Amortization		$170.0			$135.7			$116.6
Impairment of Real Estate
Corporate and Other	$36.3			—			—
Interest Expense
Regulated Operations (a)	$53.9			$49.2			$44.4

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

Corporate and Other (a)	8.6			7.1			8.2

Eliminations (a)	(2.3		)	(2.3		)	(2.3		)
Total Interest Expense	$64.9			$54.8			$50.3
Equity Earnings in ATC
Regulated Operations	$16.3			$19.6			$20.3
Income Tax Expense (Benefit)
Regulated Operations		$24.4			$39.0			$35.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	21.0			2.3			(2.3		)
U.S. Water Services	0.9			—			—

Corporate and Other	(21.0		)	(4.6		)	(4.1		)
Total Income Tax Expense		$25.3			$36.7			$28.7


(a)	During 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries. The amounts are eliminated in consolidation. Prior period segment results have been revised to conform to the current presentation as if the intercompany loan existed as of January 1, 2013.

NOTE 2. BUSINESS SEGMENTS (Continued)



As of December 31	2015		2014
Millions
Assets
Regulated Operations	$3,862.6		$3,709.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	504.6		291.9
U.S. Water Services	258.3		—

Corporate and Other	281.6		359.3
Total Assets		$4,907.1		$4,360.8
Capital Expenditures
Regulated Operations	$224.4		$583.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	8.6		4.2
U.S. Water Services	2.9		—

Corporate and Other	15.9		16.6
Total Capital Expenditures		$251.8		$604.3

- Definition

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.

+ References

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+ Details

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2015			2014
Millions
Regulated Operations		$4,336.7			$3,903.3
Construction Work in Progress	101.2			355.4
Accumulated Depreciation	(1,323.8		)	(1,260.2		)
Regulated Operations – Net	3,114.1			2,998.5
ALLETE Clean Energy	467.3			203.7
Construction Work in Progress	4.0			1.3
Accumulated Depreciation	(24.0		)	(8.4		)
ALLETE Clean Energy – Net	447.3			196.6
U.S. Water Services	15.6			—
Accumulated Depreciation	(3.4		)	—
U.S. Water Services – Net	12.2			—
Corporate and Other (a)	165.6			152.5
Construction Work in Progress	4.5			4.6
Accumulated Depreciation	(74.6		)	(67.4		)
Corporate and Other – Net	95.5			89.7
Property, Plant and Equipment – Net		$3,669.1			$3,284.8


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

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



Estimated Useful Lives of Property, Plant and Equipment
Regulated Operations		ALLETE Clean Energy	5 to 44 years
Generation	10 to 50 years	U.S. Water Services	3 to 39 years
Transmission	44 to 67 years	Corporate and Other	3 to 39 years
Distribution	18 to 65 years

NOTE 3. PROPERTY, PLANT AND EQUIPMENT (Continued)

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 (ARO) relate primarily to the decommissioning of our coal-fired and wind energy facilities and land reclamation at BNI Energy, and are included in Other Non-Current Liabilities on our 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 5. Regulatory Matters.)



Asset Retirement Obligations
Millions
Obligation as of December 31, 2013		$81.8
Accretion	5.5
Liabilities Recognized (a)	23.0
Liabilities Settled	(0.5		)
Revisions in Estimated Cash Flows	(0.6		)
Obligation as of December 31, 2014	109.2
Accretion	7.3
Liabilities Recognized (b)	5.1
Liabilities Settled	(2.6		)
Revisions in Estimated Cash Flows	12.4
Obligation as of December 31, 2015		$131.4


(a)	The increase in 2014 is related to BNI Energy for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.(See Note 7. Acquisitions.)


(b)	The increase in 2015 is related to the ALLETE Clean Energy wind energy facilities acquisitions in 2015. (See Note 7. Acquisitions.)

Jointly-Owned Facilities and Projects

12 Months Ended

Dec. 31, 2015

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 direct operating expenses of Boswell Unit 4 is included in operating expense on our 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, has assessed the transmission system and projected growth in customer demand for electricity through 2020. On April 2, 2015, the CapX2020 transmission line project from Fargo, North Dakota, to St. Cloud, Minnesota, was completed and placed in service. Minnesota Power previously participated in two additional CapX2020 projects which were completed and placed in service in 2011 and 2012.

NOTE 4. 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 As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
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
2014
Boswell Unit 4		$419.1		$209.1		$168.1	80
CapX2020 Projects	55.5		1.7		44.0		9.3 - 14.7
Total		$474.6		$210.8		$212.1

Regulatory Matters

12 Months Ended

Dec. 31, 2015

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, the FERC or the PSCW.

2010 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio. Subsequent to this last order, and as authorized by the MPUC, Minnesota Power has increased revenue under cost recovery riders for environmental, renewable and transmission investments. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Boswell Mercury Emissions Reduction Plan.) Revenue from cost recovery riders was $86.0 million in 2015 ($69.9 million in 2014 and $40.5 million in 2013).

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking legislation in June 2015. The legislation establishes that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. On November 13, 2015, Minnesota Power filed a rate schedule for EITE customers and a corresponding rider for EITE cost recovery with the MPUC. The rate proposal is revenue, and cash flow, neutral. On February 11, 2016, the MPUC dismissed the petition without prejudice, offering Minnesota Power the option to refile the petition with additional information or initiate a new petition. Minnesota Power is evaluating the MPUC’s decision.

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.

On April 21, 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. The electric service agreements with SWL&P and one other municipal customer are effective through June 30, 2019. The rates included in these 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. 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 is also determined using a cost-based formula methodology.

NOTE 5. REGULATORY MATTERS (Continued)

All of the wholesale contracts include a termination clause requiring a three-year notice to terminate. In January 2016, one of Minnesota Power’s municipal customers provided notice of its intent to terminate its contract effective June 30, 2019. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2025. Under the agreement with SWL&P, no termination notice may be given prior to June 30, 2016. The remaining 14 municipal customers may not give termination notices prior to December 31, 2021.

2012 Wisconsin Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity.

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 on June 30, 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power anticipates including its portion of the investments and expenditures for the GNTL in future transmission factor filings to include updated billing rates on customer bills.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to the 497 MW Bison Wind Energy Center in North Dakota. Customer billing rates for the Bison Wind Energy Center were approved by the MPUC in an order dated May 22, 2015. In November 2014, Minnesota Power filed a renewable resources factor filing which includes updated costs associated with Bison. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

On February 13, 2015, Minnesota Power supplemented its November 2014 renewable resources factor filing to include costs associated with the restoration and repair of Thomson. In an order dated March 5, 2015, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Annual Automatic Adjustment (AAA) of Charges. Minnesota Power’s AAA filings made in 2012, 2013, 2014 and 2015 are pending MPUC approval, and represent approximately $700 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 each AAA filing, although we cannot predict the outcome of the filings at the MPUC.

Integrated Resource Plan (IRP). In a November 2013 order, the MPUC approved Minnesota Power’s 2013 IRP which detailed its EnergyForward strategic plan, announced in January 2013. Significant elements of the EnergyForward plan include major wind investments in North Dakota which were completed in the fourth quarter of 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. On September 1, 2015, Minnesota Power filed its 2015 IRP with the MPUC which includes 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 contains the next steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in the fall of 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.

Boswell Mercury Emissions Reduction Plan. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed with project costs totaling approximately $220 million through December 31, 2015. In a November 2013 order, the MPUC approved the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Customer billing rates for the environmental improvement rider were approved by the MPUC in an order dated August 24, 2015. On September 30, 2015, Minnesota Power filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

NOTE 5. REGULATORY MATTERS (Continued)

Boswell Remaining Life Petition. On November 17, 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 is based on the significant multi-emissions retrofit work done at Boswell Unit 3 and Boswell Unit 4.

Great Northern Transmission Line (GNTL). 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 October 2013, a certificate of need application was filed with the MPUC which was approved in an order dated June 30, 2015. 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 an order dated December 17, 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In April 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 a July 2014 order, the MPUC determined the route permit application to be complete. On October 30, 2015, the Minnesota Department of Commerce and the U.S. Department of Energy released the final EIS for the GNTL. On January 4, 2016, an administrative law judge recommended approval of the route permit for the GNTL. A final decision on the route permit by the MPUC is expected in the first quarter of 2016. Manitoba Hydro must also 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. Upon receipt of all applicable permits and approvals, construction of the GNTL is expected to begin by 2017 and to be completed in 2020.

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”. In June 2013, Minnesota Power submitted a triennial filing for 2014 through 2016, which was subsequently approved by the Minnesota Department of Commerce. Minnesota Power’s CIP investment goal was $7.1 million for 2015 ($6.9 million for 2014; $6.0 million for 2013), with actual spending of $6.6 million in 2015 ($7.2 million in 2014; $6.4 million in 2013).

Minnesota requires each utility to establish an annual energy-savings goal of 1.5 percent of annual retail energy sales. On April 1, 2015, Minnesota Power submitted its 2014 CIP filing that requested a CIP financial incentive of $6.2 million. The requested CIP financial incentive was approved by the MPUC in an order dated September 16, 2015, and was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2015 and 2016. In 2014 and 2013, the CIP financial incentive recognized was $8.7 million and $7.1 million, respectively. CIP financial incentives are recognized in the period in which the MPUC approves the filing. he MPUC implemented certain limitations on amounts recoverable for the utility performance incentive program for recovery years beginning in 2015.

MISO Return on Equity Complaints. In November 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, to 9.15 percent. On February 12, 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 December 29, 2015, a federal administrative law judge ruled that the MISO transmission users have been charged an unreasonable base return on equity and proposed a reduction to 10.32 percent, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2016. As a result of these complaints filed with the FERC and the administrative law judge’s recommendation, Minnesota Power has recorded an estimated refund obligation for MISO revenue of $7.2 million and an estimated refund for MISO transmission expense of $4.5 million, resulting in a reserve of $2.7 million as of December 31, 2015; $1.5 million was attributable to prior years.

NOTE 5. REGULATORY MATTERS (Continued)

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial 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 kilowatts or less. Minnesota Power has two solar projects under development. On August 21, 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at Camp Ripley, a Minnesota Army National Guard base and training facility near Little Falls, Minnesota. At a hearing on January 28, 2016, the MPUC approved the Camp Ripley solar project as eligible to meet the solar energy standard and for current cost recovery, subject to certain compliance requirements. On September 10, 2015, Minnesota Power filed for MPUC approval of a 1 MW community solar garden project in Saint Louis County, Minnesota. If the community solar garden project is also approved, Minnesota Power believes these projects will meet approximately one-third of the overall mandate and approximately one-fourth of the mandate related to solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Costs associated with these projects are expected to be recovered from customers.

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 5. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2015		2014
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$10.6		$16.3
Total Current Regulatory Assets	10.6		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	219.3		223.9
Income Taxes (c)	64.2		46.6
Cost Recovery Riders (d)	58.0		59.7
Asset Retirement Obligations (e)	21.6		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	3.9		4.3
Total Non-Current Regulatory Assets	372.0		357.3
Total Regulatory Assets		$382.6		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$58.0		$42.9
Plant Removal Obligations	22.1		22.8
Income Taxes (c)	6.1		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	0.9		3.5
Other	17.9		11.6
Total Non-Current Regulatory Liabilities		$105.0		$94.2


(a)	Current regulatory assets are included in 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 17. 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 the Bison Wind Energy Center, 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, 2015 will be recovered over 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.

Investment in ATC

12 Months Ended

Dec. 31, 2015

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, 2015, our equity investment in ATC was $124.5 million ($121.1 million at December 31, 2014). On January 29, 2016, we invested an additional $1.2 million in ATC. In total, we expect to invest approximately $6.2 million throughout 2016.



ALLETE’s Investment in ATC
Year Ended December 31	2015			2014
Millions
Equity Investment Beginning Balance		$121.1			$114.6
Cash Investments	1.6			3.9
Equity in ATC Earnings	16.3			19.6
Distributed ATC Earnings	(14.5		)	(17.0		)
Equity Investment Ending Balance		$124.5			$121.1



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2015		2014
Millions
Current Assets		$80.5		$66.4
Non-Current Assets	3,957.6		3,728.7
Total Assets		$4,038.1		$3,795.1
Current Liabilities		$330.3		$313.1
Long-Term Debt	1,800.0		1,701.0
Other Non-Current Liabilities	245.0		163.8
Members’ Equity	1,662.8		1,617.2
Total Liabilities and Members’ Equity		$4,038.1		$3,795.1



Income Statement Data
Year Ended December 31	2015		2014		2013
Millions
Revenue		$615.8		$635.0		$626.3
Operating Expense	319.3		307.4		295.1
Other Expense	96.1		88.9		83.6
Net Income		$200.4		$238.7		$247.6
ALLETE’s Equity in Net Income		$16.3		$19.6		$20.3

Our equity earnings in ATC for the year ended December 31, 2015, were $16.3 million and reflected a $5.2 million reduction related to complaints filed with the FERC by several customer groups located within the MISO service area; of which $2.4 million was attributable to ATC’s change in estimate of a refund liability relating to prior years. The groups requested, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. ATC's current authorized return on equity is 12.2 percent. On February 12, 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 December 29, 2015, a federal administrative law judge ruled that the MISO transmission users have been charged an unreasonable base return on equity and proposed a reduction to 10.32 percent, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is currently expected in 2016. 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 on an after-tax basis ($0.9 million pre-tax).

Acquisitions

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

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 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, 2015, and 2014.

2015 Activity.

U.S. Water Services. On February 10, 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 to be paid through 2019. The contingent consideration is presented within Other Non-Current Liabilities on the Consolidated Balance Sheet. The Consolidated Statement of Income reflects 100 percent of the results of operations for U.S. Water Services since the acquisition date as the Company has acquired 100 percent of U.S. Water Services.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.



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 will be 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 will be 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 8. 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.

NOTE 7. ACQUISITIONS (Continued)

2015 Activity (Continued)

Chanarambie/Viking. On April 15, 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 PPAs in place for their entire output, which expire in 2018 (12 MW) and 2023 (85.5 MW).



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 Purchase 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 Power Purchase Agreements.

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. On July 1, 2015, ALLETE Clean Energy acquired 100 percent of a wind energy facility located near Troy, Pennsylvania (Armenia Mountain) from The AES Corporation (AES) 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 PPAs in place for its entire output, which expire in 2024.

NOTE 7. ACQUISITIONS (Continued)

2015 Activity (Continued)



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 Power Purchase Agreements 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 Power Purchase Agreements, $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.

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. On November 1, 2015, U.S. Water Services acquired 100 percent of A and W Technologies, Inc. (AWT). Total consideration for the transaction was $9.2 million, which included payment of $8.2 million in cash and a $1.0 million payment due in April 2016. 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)	4.3
Total Assets Acquired		$9.3
Liabilities Assumed
Current Liabilities		$0.1
Total Liabilities Assumed	$0.1
Net Identifiable Assets Acquired		$9.2


(a)	Intangible Assets include customer relationships and non-compete agreements. (See Note 8. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in $4.3 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.

NOTE 7. ACQUISITIONS (Continued)

2015 Activity (Continued)

Montana-Dakota Utilities. In November 2014, ALLETE Clean Energy acquired a business for $27.0 million to develop a wind energy facility near Hettinger, North Dakota. ALLETE Clean Energy constructed a 107 MW wind energy facility consisting of 43 turbines, which was approved to be sold to Montana-Dakota Utilities by the NDPSC on June 30, 2015. Construction and sale of the wind energy facility were completed in December 2015 with revenue totaling $197.7 million.

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 liabilities assumed at the date of acquisition. Fair value measurements were valued primarily using the replacement cost method and determined that the assets acquired amounted to cash of $3.6 million and construction in process of $23.4 million. There were no liabilities assumed and no recognition of goodwill.

For the year ended December 31, 2015, revenue of $197.7 million and cost of sales of $162.9 million were recognized related to the sale of the wind energy facility to Montana-Dakota Utilities and were reported on the Consolidated Statement of Income as Operating Revenue and Cost of Sales, respectively.

As of December 31, 2014, contract billings received were $54.3 million and construction costs incurred (including the construction costs acquired) were $48.2 million and were classified as Current Liabilities - Other and Prepayments and Other, respectively, on the Consolidated Balance Sheet.

2014 Activity.

ACE Wind Acquisition. In January 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 7. 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 Purchase 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 Power Purchase Agreements.


(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 February 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 December 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 7. 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 Purchase 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 Power Purchase Agreements.

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

- Definition

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).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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+ Details

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The following table summarizes changes to goodwill by reportable segment for the year ended December 31, 2015:



	ALLETE Clean Energy		U.S. Water Services		Total
Millions
Balance as of December 31, 2014		$2.9	—			$2.9
Acquired Goodwill	0.4			$127.3	127.7
Balance as of December 31, 2015		$3.3		$127.3		$130.6

Balances of intangible assets, net, excluding goodwill as of December 31, 2015, are as follows:



	December 31, 2014		Additions (a)		Amortization	Other (b)	December 31, 2015
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	—			$64.0	$(3.2)	—		$60.8
Developed Technology and Other (c)		$1.9	6.4		(0.8)	$(0.3)	7.2
Total Definite-Lived Intangible Assets	1.9		70.4		(4.0)	(0.3)	68.0
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	—		16.6		n/a	—	16.6
Total Intangible Assets		$1.9		$87.0	$(4.0)	$(0.3)		$84.6


(a)	Additions are primarily the result of the U.S. Water Services acquisition. (See Note 7. Acquisitions.)


(b)	Armenia Mountain was acquired on July 1, 2015, at which time the purchase option intangible asset was reclassified as a component of the acquisition consideration.


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

NOTE 8. GOODWILL AND INTANGIBLE ASSETS (Continued)

Customer relationships have a useful life of approximately 22 years and developed technology and other have useful lives ranging from approximately 3 years to approximately 13 years (weighted average of approximately 9 years). The weighted average useful life of all definite-lived intangible assets as of December 31, 2015, is approximately 21 years.

Amortization expense of intangible assets for the year ended December 31, 2015, was $4.0 million. Accumulated amortization was $4.1 million and $0.1 million as of December 31, 2015, and December 31, 2014, respectively. Estimated annual amortization expense for definite-lived intangible assets is $5.1 million in 2016, $5.0 million in 2017, $4.7 million in 2018, $4.4 million in 2019, $4.2 million in 2020, and $44.6 million thereafter.

- Definition

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

+ References + Details

Investments

12 Months Ended

Dec. 31, 2015

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At December 31, 2015, 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	2015		2014
Millions
ALLETE Properties (a)		$50.1		$88.2
Available-for-sale Securities (b)	18.5		18.9
Cash Equivalents	2.0		2.9
Other	4.0		4.4
Total Other Investments		$74.6		$114.4


(a)	In 2015, ALLETE Properties recorded a $36.3 million non-cash impairment charge related to its real estate assets. (See Note 1. Operations and Significant Accounting Policies.)


(b)	As of December 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was none, in one year to less than three years was $1.0 million, in three years to less than five years was $3.2 million, and in five or more years was $6.7 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 a $36.3 million non-cash impairment was recorded for the year ended December 31, 2015 (none for the years ended December 31, 2014 and 2013). (See Note 1. Operations and Significant Accounting Policies.)

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.



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2015	$20.0	—	$1.5	$18.5
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2015		$1.7	$0.1	—
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—

Fair Value

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value [Text Block]

FAIR VALUE

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

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

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, fixed income securities, and derivative instruments consisting of cash flow hedges.

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, 2015 and 2014. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.



	Fair Value as of December 31, 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.

NOTE 10. FAIR VALUE (Continued)



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.1	—		—		$8.1
Available-for-sale – Corporate Debt Securities	—			$10.8	—	10.8
Cash Equivalents	2.9		—		—	2.9
Total Fair Value of Assets		$11.0		$10.8	—		$21.8

Liabilities:
Deferred Compensation (b)	—			$16.2	—		$16.2
Derivatives – Interest Rate Swap (c)	—		0.3		—	0.3
Total Fair Value of Liabilities	—			$16.5	—		$16.5
Total Net Fair Value of Assets (Liabilities)		$11.0	$(5.7)		—		$5.3


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


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


(c)	Included in Current Liabilities - Other 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, 2015. The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value is measured based on the consideration expected to be transferred, discounted to present value. The discount rate is 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 our Consolidated Statement of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, or in 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. The acquisition contingent consideration was measured at $36.6 million as of December 31, 2015.



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 Expense (a)	2.4
Changes in Cash Flow Projections	(1.5		)
Balance as of December 31, 2015		$36.6


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

The Level 3 activity above is the result of the February 10, 2015, acquisition of U.S. Water Services. There was no activity in Level 3 during the year ended December 31, 2014.

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 2015 and 2014, there were no transfers in or out of Levels 1, 2 or 3.

NOTE 10. FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the item listed in the table below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item below 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 Current Portion
December 31, 2015	$1,605.0	$1,676.0
December 31, 2014	$1,373.5	$1,484.5

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, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. (See Note 6. Investment in ATC.) The aggregate carrying amount of the investment was 124.5 million as of December 31, 2015 (121.1 million as of December 31, 2014). 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, 2015 and 2014, there were no indicators of impairment.

Goodwill. To align with the annual budgeting and forecasting process, 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 on February 10, 2015. The aggregate carrying amount of goodwill was $130.6 million as of December 31, 2015 and $2.9 million as of December 31, 2014.

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. As of December 31, 2015, there have been no events or changes in circumstance which would indicate impairment of our goodwill.

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 on February 10, 2015. The aggregate carrying amount of intangible assets was $84.6 million as of December 31, 2015 ($1.9 million as of December 31, 2014). 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, 2015, there have been no events or changes in circumstance which would indicate impairment of our intangible assets.

NOTE 10. FAIR VALUE (Continued)

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. For the years ended December 31, 2015 and 2014, there were no indicators of impairment.

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. Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to natural gas in 2015, which were actions included in Minnesota Power’s 2013 IRP approved by the MPUC in a November 2013 order. On September 1, 2015, Minnesota Power filed its 2015 IRP with the MPUC. The 2015 IRP contains the next steps for Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016 and the ceasing of coal-fired operations at Taconite Harbor in 2020. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2, or the conversion of Laskin. In addition, we expect to be able to continue depreciating these assets over their established remaining useful lives; however, we are unable to predict the impact of unanticipated regulatory outcomes resulting in changes to their established remaining useful lives. The remaining net book value for Taconite Harbor as of December 31, 2015 was approximately $100 million. We would seek recovery in a general rate case of additional depreciation expense as a result of material changes in useful lives.

- Definition

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

+ References + Details

Short-Term and Long-Term Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2015, total short-term debt outstanding was $37.9 million ($104.4 million as of December 31, 2014) and consisted of long-term debt due within one year and notes payable.

As of December 31, 2015, we had bank lines of credit aggregating $408.4 million ($408.4 million as of December 31, 2014), the majority of which expire in November 2018. We had $12.4 million outstanding in standby letters of credit and $1.6 million outstanding in draws under our lines of credit as of December 31, 2015 ($47.5 million in standby letters of credit and $3.7 million in draws outstanding as of December 31, 2014).

Long-Term Debt. As of December 31, 2015, total long-term debt outstanding was $1,568.7 million ($1,272.8 million as of December 31, 2014). The aggregate amount of long-term debt maturing in 2016 is $36.3 million ($193.6 million in 2017; $64.1 million in 2018; $56.5 million in 2019; $103.0 million in 2020; and $1,151.5 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.

On July 1, 2015, ALLETE Clean Energy assumed $60.9 million of long-term debt at fair value, including $5.9 million due within one year, in conjunction with ALLETE Clean Energy’s acquisition of Armenia Mountain. (See Note 7. Acquisitions.) On November 5, 2015, the assumed debt was refinanced when Armenia Mountain Wind, LLC (Armenia Mountain) entered into a Note Purchase and Guarantee Agreement (NPA) with AMW I Holding, LLC (Guarantor) and the purchasers named therein. Both Armenia Mountain and the Guarantor are wholly owned subsidiaries of ALLETE Clean Energy. Under the NPA, Armenia Mountain issued and sold $84.5 million of its 3.26 percent Senior Secured Notes (Notes) due December 31, 2024, to certain institutional accredited investors in the private placement market. The Notes were issued and 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.

Interest on the Notes is payable semi-annually on June 30 and December 31 of each year, commencing on December 31, 2015. Armenia Mountain has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision; however, the Notes are redeemable at par, including accrued and unpaid interest, three months prior to the maturity date. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Armenia Mountain used a portion of the proceeds to refinance the debt assumed in the Armenia Mountain acquisition and plans to use the remaining proceeds for general corporate purposes. Armenia Mountain’s obligations under the Notes are secured by its assets and a pledge by the Guarantor of its equity interests in Armenia Mountain. There is no recourse to ALLETE or any other subsidiary of ALLETE with respect to the Armenia Mountain’s obligations under the Notes other than to itself and its direct owner, the Guarantor, which guarantees payment under the Notes.

NOTE 11. SHORT-TERM AND LONG-TERM DEBT (Continued)

On August 25, 2015, the Company entered into a $125.0 million Term Loan Agreement with JPMorgan Chase Bank, N.A., as a lender and administrative agent, and Bank of America, N.A., as a lender (Term Loan). The Term Loan is an unsecured, single-draw loan that is due on August 25, 2017. The interest rate on the Term Loan is equal to LIBOR plus 0.625 percent. Proceeds from the Term Loan will be used for general corporate purposes, including the refinancing of the $75.0 million Term Loan Agreement due August 25, 2015.

The Term Loan contains customary conditions of borrowing, events of default and affirmative and negative covenants. The Term Loan includes a financial covenant to maintain a ratio of total indebtedness to total capitalization (as defined therein) equal to or less than 65 percent. Indebtedness under the Term Loan may be accelerated upon the occurrence of an event of default, including cross-default to other indebtedness in excess of $35.0 million.

On September 24, 2015, we issued $100.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:



Maturity Date	Principal Amount	Interest Rate
September 15, 2020	$40 Million	2.80%
September 16, 2030	$60 Million	3.86%

Interest on the Bonds is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2016. The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision; however, the September 16, 2030, series of bonds is redeemable at par, including accrued and unpaid interest, six months prior to the maturity date. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company intends to use the proceeds from the sale of the Bonds to fund utility capital expenditures and/or for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

NOTE 11. SHORT-TERM AND LONG-TERM DEBT (Continued)



Long-Term Debt
As of December 31	2015		2014
Millions
First Mortgage Bonds
7.70% Series Due 2016	$20.0		$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		—
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		—
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 2015	—		75.0
Unsecured Term Loan Variable Rate Due 2017	125.0		—
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020	13.5		24.6
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	83.3		—
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		15.0
Other Long-Term Debt, 0.08% – 7.45% Due 2016 – 2037	68.4		59.1
Total Long-Term Debt	1,605.0		1,373.5
Less: Due Within One Year	36.3		100.7
Net Long-Term Debt		$1,568.7		$1,272.8

NOTE 11. 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, 2015, our ratio was approximately 0.47 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, 2015, ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments, Guarantees and Contingencies [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 2026 (Agreement). It provides a long-term supply of energy to customers in Minnesota Power’s electric service territory and enables Minnesota Power to meet reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a 455 MW coal-fired generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a generating unit owned by Minnkota Power, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the Unit and also purchases power from Square Butte.

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to Unit output. 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 sales agreement described below. 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, 2015, Square Butte had total debt outstanding of $376.4 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2016 through 2020, 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 2015 was $77.8 million ($70.1 million in 2014; $71.1 million in 2013). 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 $10.1 million in 2015 ($10.5 million in 2014; $10.5 million in 2013). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. Minnesota Power has a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, 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 2015 (23 percent in 2014).

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

Oliver Wind I and II PPAs. Minnesota Power entered into two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) wind energy facilities located near Center, North Dakota, that expire in 2031 and 2032, respectively. Each agreement provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges, and Minnesota Power only pays for energy as it is delivered.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

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

In May 2011, Minnesota Power and Manitoba Hydro signed a third PPA. This PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the additional transmission capacity in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014. The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

In July 2014, Minnesota Power and Manitoba Hydro signed a fourth PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The pricing under this PPA is based on forward market prices. The PPA was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL. (See Great Northern Transmission Line.)

In October 2015, Minnesota Power and Manitoba Hydro signed a fifth PPA that provides for Minnesota Power to purchase 50 MW of capacity at fixed prices. The PPA begins in June 2017 and expires in May 2020.

Great River Energy PPAs. In August 2014, January 2015 and October 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA, 50 MW of capacity only under the second PPA, and 50 MW of capacity only under the third PPA. The first and second PPAs begin in June 2016 and expire in May 2020, and the third PPA begins in June 2017 and expires in May 2020. All of these contracts have fixed capacity pricing. The energy price in the first PPA 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.

TransAlta PPAs. In September 2015, Minnesota Power and TransAlta signed PPAs that provide for Minnesota Power to purchase 50 MW of energy during off-peak hours and 100 MW of energy during on-peak hours beginning in January 2017 and ending in December 2019. The energy prices are fixed throughout the terms of the PPAs.

Basin Power Sales Agreements. Minnesota Power has an agreement to sell 100 MW of capacity and energy to Basin for a ten-year period which expires in April 2020. The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on the cost of fuel. The agreement 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. On July 9, 2015, Minnesota Power entered into an additional agreement to sell 100 MW of capacity only to Basin at fixed rates for a two-year period beginning in June 2016.

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 2016 and a portion of its coal requirements through December 2019. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018. The minimum annual payment obligation under these supply and transportation agreements is $40.7 million in 2016, $27.6 million in 2017, $28.3 million in 2018 and $1.8 million in 2019. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

On January 11, 2016, Arch Coal, Inc. (Arch Coal) elected to file for reorganization under Chapter 11 of the Bankruptcy Code and announced that it reached an agreement with the majority of its senior lenders on the terms of a financial restructuring. The United States Bankruptcy Court for the Eastern District of Missouri authorized Arch Coal to enter into and perform under coal contracts in the ordinary course of business.

Leasing Agreements. BNI Energy is obligated to make lease payments for a dragline totaling $2.8 million annually for 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 2022. The aggregate amount of minimum lease payments for all operating leases is $14.0 million in 2016, $12.6 million in 2017, $11.1 million in 2018, $9.9 million in 2019, $6.9 million in 2020 and $23.2 million thereafter. Total lease expense was $17.3 million in 2015 ($14.8 million in 2014; $13.8 million in 2013).

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 and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC.

Transmission Investments. 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 on June 30, 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power anticipates including its portion of the investments and expenditures for the GNTL in future transmission factor filings to include updated billing rates on customer bills.

On April 2, 2015, the CapX2020 transmission line project from Fargo, North Dakota, to St. Cloud, Minnesota, was completed and placed in service. Minnesota Power previously participated in two additional CapX2020 projects which were completed and placed in service in 2011 and 2012.

Minnesota Power invested approximately $100 million to complete the three transmission line projects. As future CapX2020 projects are identified, Minnesota Power may participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 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 October 2013, a certificate of need application was filed with the MPUC which was approved in an order dated June 30, 2015. 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 an order dated December 17, 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In April 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 a July 2014 order, the MPUC determined the route permit application to be complete. On October 30, 2015, the Minnesota Department of Commerce and the U.S. Department of Energy released the final EIS for the GNTL. On January 4, 2016, an administrative law judge recommended approval of the route permit for the GNTL. A final decision on the route permit by the MPUC is expected in the first quarter of 2016. Manitoba Hydro must also 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. Upon receipt of all applicable permits and approvals, construction of the GNTL is expected to begin by 2017 and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. 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. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration or have already been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional regulation under many of these proposals. In preparation and 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 although many of the state and federal environmental regulations have been finalized, or will 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 ranges of future 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 charged to expense 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 applicable emission requirements.

New Source Review (NSR). In August 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 (Court) in September 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. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. Minnesota Power’s 2015 IRP filed with the MPUC on September 1, 2015, outlined Minnesota Power’s preferred option to reroute emissions from Units 1 and 2 through existing emission control technology at Boswell Unit 3. We are required to notify the EPA no later than December 31, 2016, whether we will retire, refuel, repower or reroute Boswell Units 1 and 2. We believe that future capital expenditures or costs to retire would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In April 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit in June 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. In October 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017.

CSAPR requires a total of 28 states in the eastern half of the United States, including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. 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.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NO_x and SO₂ Phase I allowances already issued, and our review of the projected CSAPR 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 February 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 with project costs totaling approximately $220 million through December 31, 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 January 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the retirement at Unit 3 with MISO’s resource planning year. Taconite Harbor Unit 3 was retired in May 2015.

On June 29, 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. On December 15, 2015, the U.S. Court of Appeals for the D.C. Circuit rejected a motion by utilities and states to vacate the MATS rule, ordering the rule stayed while the EPA completes its review. The U.S. Supreme Court decision is not expected to have a material impact on Minnesota Power generation due to ongoing 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.

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 December 2012. Major existing sources had until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist 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 to more stringently control emissions that result in ground level ozone. In January 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. On October 26, 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, so voluntary efforts to reduce ozone continue in the state. No additional costs for compliance are anticipated at this time.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 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 December 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 also 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 December 2013, based on already available monitoring data, and issued designations of the 2012 revised primary annual fine particulate attainment status in December 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. Accordingly, the 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 April 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 June 2013. However, the State of Minnesota delayed completing the documents pending EPA guidance to states for preparing the SIP submittal.

In September 2013 the EPA provided guidance to states regarding implementation of the one-hour NO₂ NAAQS and in June 2014, as clarified on February 3, 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 January 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. On October 20, 2015, the EPA published in the Federal Register an approval and partial disapproval of the June 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.

On August 10, 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. Boswell and Taconite Harbor are the only Minnesota Power generating facilities subject to the DRR. The MPCA has informed Minnesota Power that compliant SO₂ modeling recently completed at these facilities should satisfy the DRR obligations, and no further modeling should be required. The MPCA is in discussion with the EPA to confirm its conclusion. The MPCA is required to inform the EPA which sources are subject to the rule by January 15, 2016, and how each source will evaluate air quality by July 1, 2016. As such, additional compliance costs for the one-hour SO₂ NAAQS are not expected at this time.

Class I Air Quality Petitions and Requests. In July 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 applied for and 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. The Company has requested additional clarification from the Fond du Lac Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In May 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 June 2013, President Obama announced a 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 May 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.

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 June 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established lower 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.

In March 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 September 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO₂ emissions.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In June 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” (CPP). The EPA issued the final CPP on August 3, 2015, together with a proposed federal implementation plan and a model rule for emissions trading. Numerous petitions for review of the rule have been 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.

The CPP establishes 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 constitute 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 goals, 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 CPP, each state is required to develop a state implementation plan by September 6, 2016, or by September 6, 2018, if granted an extension. If the CPP is upheld at the completion of the appellate court process, all of these deadlines are likely to be reset based on the length of time that the appeals process takes.

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 and 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 5. Regulatory Matters.)

We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. Minnesota Power would seek recovery of any additional costs through cost recovery riders or in a general rate case.

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 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 power purchase agreements 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 May 2014.

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 April 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 published in the Federal Register in August 2014, with an effective date in October 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 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; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. Minnesota Power would seek recovery of any additional costs through a general rate case.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Steam Electric Power Generating Effluent Guidelines. In April 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 on September 30, 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.

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 cost recovery riders or in a general rate case.

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 five of its electric generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. 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 June 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 December 2014 under Subtitle D (non-hazardous) of RCRA and it was published in the Federal Register on April 27, 2015. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 10 years and be between approximately $80 million and $100 million. Minnesota Power has not disposed ash onsite at Taconite Harbor since the effective date of the rule, and therefore, the CCR rule is not applicable to that generating facility. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. Minnesota Power would seek recovery of any additional costs through a general rate case.

Other Matters

ALLETE Clean Energy. ALLETE Clean Energy acquired wind energy facilities in 2014 and 2015, which have PPAs in place for their entire output and expire in various years between 2018 and 2032. (See Note 7. Acquisitions.)

U.S. Water Services. As of December 31, 2015, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of December 31, 2015, 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 the 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.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

ALLETE Properties. As of December 31, 2015, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.3 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $6.3 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 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 November 2006 for Town Center and November 2007 for Palm Coast Park. 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. At December 31, 2015, we owned 72 percent of the assessable land in the Town Center District (72 percent at December 31, 2014) and 89 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2014). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

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

Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2015

Common Stock and Earnings Per Share [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, 2012	39,377		$784.7
Employee Stock Purchase Program	16	0.7
Invest Direct	395	18.5
Options and Stock Awards	301	17.9
Equity Issuance Program	1,312	63.4
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
Contribution 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	1,413	65.4
Balance as of December 31, 2015	49,075		$1,271.4

NOTE 13. 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 February 2015, 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 4.0 million shares remain available for issuance. For the year ended December 31, 2015, 1.3 million shares of common stock were issued under this agreement resulting in net proceeds of $69.9 million (1.9 million shares for net proceeds of $90.0 million for the year ended December 31, 2014; 1.3 million shares for net proceeds of $63.4 million for the year ended December 31, 2013). The shares sold January 1, 2013 through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, 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 2015, 2014 and 2013.

Forward Sale Agreement and Issuance of Common Stock. In February 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 September 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 on February 4, 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. No contributions were made to the pension plan for the year ended December 31, 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; no contributions were made in 2013. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
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
2013
Net Income Attributable to ALLETE		$104.7			$104.7
Average Common Shares	39.7		0.1	39.8
Earnings Per Share		$2.64			$2.63

Income Tax Expense

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2015			2014			2013
Millions
Current Tax Expense
Federal (a)	—			$1.1			—
State (a)	$0.2			2.9			$0.1
Total Current Tax Expense	0.2			4.0			0.1
Deferred Tax Expense
Federal	19.4			25.3			22.9
State	6.5			8.2			6.5
Investment Tax Credit Amortization	(0.8		)	(0.8		)	(0.8		)
Total Deferred Tax Expense	25.1			32.7			28.6
Total Income Tax Expense		$25.3			$36.7			$28.7

(a)

For the years ended December 31, 2015, 2014, and 2013, 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.



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2015			2014			2013
Millions
Income Before Non-Controlling Interest and Income Taxes		$166.8			$162.2			$133.4
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$58.4			$56.8			$46.7
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	4.4			7.2			4.3
Regulatory Differences for Utility Plant	(0.6		)	(3.5		)	(2.2		)
Production Tax Credits	(37.0		)	(23.7		)	(19.2		)
Other	0.1			(0.1		)	(0.9		)
Total Income Tax Expense		$25.3			$36.7			$28.7

The effective tax rate on income was 15.2 percent for 2015 (22.6 percent for 2014; 21.5 percent for 2013). The 2015, 2014, and 2013 effective rates were primarily impacted by production tax credits and by the deduction for AFUDC–Equity (included in Regulatory Differences for Utility Plant in the preceding table).

NOTE 15. INCOME TAX EXPENSE (Continued)



Deferred Tax Assets and Liabilities
As of December 31	2015			2014
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$105.4			$102.2
Property Related	126.6			102.7
NOL Carryforwards	186.4			156.5
Tax Credit Carryforwards	164.8			95.7
Power Purchase Agreements	73.0			51.8
Other	21.8			17.0
Gross Deferred Tax Assets	678.0			525.9
Deferred Tax Asset Valuation Allowance	(31.6		)	(22.1		)
Total Deferred Tax Assets		$646.4			$503.8
Deferred Tax Liabilities
Property Related		$1,053.0			$848.8
Regulatory Asset for Benefit Obligations	89.4			89.9
Unamortized Investment Tax Credits	26.0			10.3
Partnership Basis Differences	47.8			41.9
Other	10.0			16.1
Total Deferred Tax Liabilities		$1,226.2			$1,007.0
Net Deferred Income Taxes		$579.8			$503.2
Recorded as:
Net Current Deferred Tax Assets (a)	—			$7.5
Net Long-Term Deferred Tax Liabilities		$579.8		510.7
Net Deferred Income Taxes		$579.8			$503.2


(a)	For discussion of classification of deferred income taxes see Note 1. Operations and Significant Accounting Policies - New Accounting Standards - Balance Sheet Classification of Deferred Taxes.



NOL and Tax Credit Carryforwards
As of December 31	2015	2014
Millions
Federal NOL Carryforwards (a)	$493.0		$413.7
Federal Tax Credit Carryforwards	$113.6	$59.3
State NOL Carryforwards (a)	$228.6	$184.7
State Tax Credit Carryforwards (b)	$20.0	$14.7


(a)	Pretax amounts.


(b)	Net of a $31.2 million valuation allowance as of December 31, 2015 ($21.7 million as of December 31, 2014).

The federal NOL and tax credit carryforward periods expire between 2030 and 2035. 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, 2015. The state NOL and tax credit carryforward periods expire between 2025 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.

NOTE 15. INCOME TAX EXPENSE (Continued)



Gross Unrecognized Income Tax Benefits	2015			2014			2013
Millions
Balance at January 1		$2.0			$1.2			$2.7
Additions for Tax Positions Related to the Current Year	0.5			—			0.1
Additions for Tax Positions Related to Prior Years	0.7			1.0			1.3
Reductions for Tax Positions Related to Prior Years	(0.7		)	—			—
Reductions for Settlements	—			—			(2.9		)
Lapse of Statute	(0.1		)	(0.2		)	—
Balance as of December 31		$2.4			$2.0			$1.2

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, 2015, included $0.5 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $2.9 million in 2013 was due to the removal of our uncertain tax positions for positions effectively settled with the Internal Revenue Service for tax years 2005 through 2009.

As of December 31, 2015, we had no accrued interest (none as of December 31, 2014; $0.5 million as of December 31, 2013) related to unrecognized tax benefits included on our 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 our Consolidated Statement of Income. Interest expense related to unrecognized tax benefits on our Consolidated Statement of Income was immaterial in 2015 (immaterial in 2014, and in 2013). There were no penalties recognized in 2015, 2014 or 2013. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on our 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 2012 or state examination for years before 2011.

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2015

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 common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale securities, defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits, and gains and losses on derivatives accounted for as cash flow hedges.

NOTE 16. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)(Continued)

Changes in accumulated other comprehensive loss, net of tax, for the years ended December 31, 2015, 2014 and 2013, 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, 2012	$(0.1)		$(21.5)		$(0.4)		$(22.0)
Other Comprehensive Income Before Reclassifications	1.3		3.2		0.1		4.6
Amounts Reclassified From Accumulated Other Comprehensive Loss	(1.3	)	1.6		—		0.3
Net Other Comprehensive Income	—		4.8		0.1		4.9
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)


(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 17. Pension and Other Postretirement Benefit Plans.)

- Definition

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.

+ References + Details

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. We made no contributions to the plans in 2015 ($19.5 million in 2014; none in 2013). We also have a defined contribution RSOP covering substantially all employees. The 2015 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $9.0 million ($9.1 million for the 2014 plan year; $8.4 million for the 2013 plan year). (See Note 13. Common Stock and Earnings Per Share and Note 18. 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.

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 2015, no contributions were made to the VEBAs (none in 2014; $10.8 million in 2013) and no contributions were made to the grantor trusts (none in 2014; $2.0 million in 2013).

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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 to contribute $2.0 million to the defined benefit pension plan and expect no contributions to the defined benefit postretirement health and life plan in 2016.

Accounting for defined benefit pension and 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 our 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
At December 31	2015			2014
Millions
Accumulated Benefit Obligation		$665.0			$661.4
Change in Benefit Obligation
Obligation, Beginning of Year		$714.5			$622.8
Service Cost	10.1			8.3
Interest Cost	29.9			29.8
Actuarial (Gain) Loss	(31.2		)	72.6
Benefits Paid	(40.2		)	(36.9		)
Participant Contributions	26.7			17.9
Obligation, End of Year		$709.8			$714.5
Change in Plan Assets
Fair Value, Beginning of Year		$544.2			$501.6
Actual Return on Plan Assets	(10.8		)	41.0
Employer Contribution (a)	28.1			38.5
Benefits Paid	(40.2		)	(36.9		)
Fair Value, End of Year		$521.3			$544.2
Funded Status, End of Year	$(188.5)			$(170.3)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.3)			$(1.2)
Non-Current Liabilities	$(187.2)			$(169.1)


(a)	Includes Participant Contributions noted above.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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



Unrecognized Pension Costs
As of December 31	2015		2014
Millions
Net Loss		$252.7		$250.4
Prior Service Cost	—		0.2
Total Unrecognized Pension Costs		$252.7		$250.6



Components of Net Periodic Pension Expense
Year Ended December 31	2015			2014			2013
Millions
Service Cost		$10.1			$8.3			$9.9
Interest Cost	29.9			29.8			26.0
Expected Return on Plan Assets	(40.7		)	(38.2		)	(35.2		)
Amortization of Loss	17.9			14.2			21.5
Amortization of Prior Service Cost	0.2			0.3			0.3
Net Pension Expense		$17.4			$14.4			$22.5



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2015		2014
Millions
Net Loss	$20.2		$69.8
Amortization of Prior Service Cost	(0.2	)	(0.3	)
Amortization of Loss	(17.9	)	(14.2	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$2.1		$55.3



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2015		2014
Millions
Projected Benefit Obligation		$709.8		$714.5
Accumulated Benefit Obligation		$665.0		$661.4
Fair Value of Plan Assets		$521.3		$544.2

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Postretirement Health and Life Obligation and Funded Status
At December 31	2015			2014
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$170.9			$151.9
Service Cost	4.3			3.4
Interest Cost	7.2			7.3
Actuarial (Gain) Loss	(14.4		)	18.1
Benefits Paid	(10.7		)	(8.9		)
Participant Contributions	2.9			2.6
Plan Amendments	—			(2.9		)
Plan Curtailments	—			(0.6		)
Obligation, End of Year		$160.2			$170.9
Change in Plan Assets
Fair Value, Beginning of Year		$163.2			$157.0
Actual Return on Plan Assets	(3.5		)	11.6
Employer Contribution	1.5			1.1
Participant Contributions	2.9			2.6
Benefits Paid	(10.7		)	(9.1		)
Fair Value, End of Year		$153.4			$163.2
Funded Status, End of Year	$(6.8)			$(7.7)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$6.4			$6.6
Current Liabilities	$(1.0)			$(0.9)
Non-Current Liabilities	$(12.2)			$(13.4)

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 $17.4 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2015 ($17.9 million at December 31, 2014).

The postretirement health and life costs that are reported as a component within our 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	2015		2014
Millions
Net Loss	$6.5		$6.9
Prior Service Credit	(7.6	)	(10.6	)
Total Unrecognized Postretirement Health and Life Credit	$(1.1)		$(3.7)

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2015			2014			2013
Millions
Service Cost		$4.3			$3.4			$3.9
Interest Cost	7.2			7.3			6.8
Expected Return on Plan Assets	(10.9		)	(10.3		)	(9.7		)
Amortization of Loss	0.4			0.5			1.6
Amortization of Prior Service Credit	(3.0		)	(2.5		)	(2.5		)
Effect of Plan Settlement (a)	—			—			(1.6		)
Net Postretirement Health and Life Credit	$(2.0)			$(1.6)			$(1.5)


(a)	Result of the termination of a legacy benefit plan.



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2015			2014
Millions
Net Loss	—			$16.4
Prior Service Credit Arising During the Period	—			(3.0	)
Amortization of Prior Service Credit		$3.0		2.5
Amortization of Loss	(0.4		)	(0.5	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$2.6			$15.4



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2016		$39.8		$8.3
2017		$40.6		$8.6
2018		$41.1		$8.8
2019		$41.7		$9.1
2020		$41.8		$9.3
Years 2021 – 2025		$216.2		$48.0

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, 2016, are as follows:



	Pension	Postretirement Health and Life
Millions
Net (Gain) Loss	$(8.4)	$0.2
Prior Service Credit	—	(2.9)
Total Pension and Postretirement Health and Life Credit	$(8.4)	$(2.7)

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Assumptions Used to Determine Benefit Obligation
As of December 31	2015	2014
Discount Rate
Pension	4.72%	4.30%
Postretirement Health and Life	4.73%	4.33%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	6.50%	6.75%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2022



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2015	2014	2013
Discount Rate	4.30 - 4.33%	4.93 - 4.96%	4.10 - 4.13%
Expected Long-Term Return on Plan Assets
Pension	8.00%	8.00%	8.25%
Postretirement Health and Life	6.40 - 8.00%	6.40 - 8.00%	6.60 - 8.25%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%	4.30 - 4.60%

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 yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation.

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-Percentage-Point Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.9	$(1.5)
Effect on Postretirement Health and Life Obligation		$19.3	$(15.9)



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2015		2014		2015		2014
Equity Securities	47	%	48	%	57	%	58	%
Debt Securities	39	%	39	%	35	%	34	%
Private Equity	8	%	8	%	8	%	8	%
Real Estate	6	%	5	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities as of December 31, 2015 (no shares as of December 31, 2014).

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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. Below are the current targeted allocations as of December 31, 2015.



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 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Fair Value



	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
Other Types of Investments:
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 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$56.4	—			$88.5
U.S. Mid-cap Growth (a)	13.6		23.9		—		37.5
U.S. Small-cap (a)	13.9		24.4		—		38.3
International	46.1		45.9		—		92.0
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		201.0		—		203.7
Cash and Cash Equivalents	11.9		—		—		11.9
Other Types of Investments:
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$120.4		$351.6		$72.2		$544.2

(a)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2013		$46.8			$26.5
Actual Return on Plan Assets	1.2			2.8
Purchases, Sales, and Settlements – Net	(4.7		)	(0.4		)
Balance as of December 31, 2014		$43.3			$28.9

Postretirement Health and Life Fair Value



	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
Other Types of Investments:
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 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 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



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$29.3	—		—			$29.3
U.S. Mid-cap Growth (a)	20.0		—		—		20.0
U.S. Small-cap (a)	12.6		—		—		12.6
International	30.6		—		—		30.6
Debt Securities:
Mutual Funds	44.5		—		—		44.5
Fixed Income	—			$9.9	—		9.9
Cash and Cash Equivalents	3.4		—		—		3.4
Other Types of Investments:
Private Equity Funds	—		—			$12.9	12.9
Total Fair Value of Assets		$140.4		$9.9		$12.9		$163.2


(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, 2013		$13.1
Actual Return on Plan Assets	1.4
Purchases, Sales, and Settlements – Net	(1.6		)
Balance as of December 31, 2014		$12.9

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, 2015

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 newly issued 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 $9.0 million in 2015 ($9.1 million in 2014; $8.4 million in 2013).

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	2015	2014		2013
Millions
ESOP Shares
Allocated	1.8	1.9		2.0
Unallocated	—	0.3		0.5
Total	1.8	2.2		2.5
Fair Value of Unallocated Shares	—		$13.2		$24.1

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 1.1 million shares of common stock reserved for issuance under the Executive Plan, with 0.9 million of these shares available for issuance as of December 31, 2015.

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.

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

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

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

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

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

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



Share-Based Compensation Expense
Year Ended December 31	2015		2014		2013
Millions
Performance Shares		$1.8		$1.6		$1.7
Restricted Stock Units	0.8		0.7		0.7
Total Share-Based Compensation Expense		$2.6		$2.3		$2.4
Income Tax Benefit		$1.1		$1.0		$1.0

There were no capitalized share-based compensation costs during the years ended December 31, 2015, 2014 or 2013.

As of December 31, 2015, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.9 million and $1.1 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and 1.9 years for restricted stock units.

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

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



	2015				2014				2013
	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	66,279			$44.39	108,299			$44.10	395,678			$42.28
Granted (a)	—		—		—		—		—		—
Exercised	(24,456	)		$44.52	(42,020	)		$43.65	(287,379	)		$41.60
Forfeited	(2,169	)	$42.93		—		—		—		—
Outstanding as of December 31	39,654			$44.39	66,279			$44.39	108,299			$44.10
Exercisable as of December 31	39,654			$44.39	66,279			$44.39	108,299			$43.17


(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 approximately $1.1 million in 2015. 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 $0.2 million during 2015 ($0.4 million in 2014; $2.2 million in 2013).



	Exercise Price
As of December 31, 2015	$39.10		$44.15		$48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	16,620		2,306		20,728
Weighted Average Remaining Contractual Life (Years)	2.1		0.1		1.1
Weighted Average Exercise Price		$39.10		$44.15		$48.65
Aggregate Intrinsic Value (Millions)		$0.2	—			$0.1

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



	2015				2014				2013
	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	119,635			$48.26	114,765			$47.02	107,899			$40.73
Granted (a)	43,583			$58.95	47,992			$46.47	45,830			$52.15
Awarded	—		—		(36,515	)		$42.01	(18,605	)		$35.10
Unearned Grant Award	(36,670	)		$45.41	—		—		(18,606	)		$35.10
Forfeited	(7,008	)		$53.49	(6,607	)		$48.29	(1,753	)		$47.26
Non-vested as of December 31	119,540			$52.72	119,635			$48.26	114,765			$47.02

(a) Shares granted include accrued dividends.

There were 51,586 performance shares granted in January 2016 for the three-year performance period ending in 2018. 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 $2.7 million.

There were no performance shares awarded in February 2016 for the three-year performance period ending in 2015.

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

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



	2015				2014				2013
	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	53,888			$44.47	55,982			$40.85	56,415			$36.61
Granted (a)	26,702			$54.81	19,645			$48.44	21,440			$43.41
Awarded	(19,464	)		$41.44	(18,860	)		$37.64	(20,939	)		$32.03
Forfeited	(3,432	)		$51.52	(2,879	)		$45.92	(934	)		$41.02
Available as of December 31	57,694			$49.86	53,888			$44.47	55,982			$40.85

(a) Shares granted include accrued dividends.

There were 17,396 restricted stock units granted in January 2016 for the vesting period ending in 2018. The grant date fair value of the restricted stock units granted was $0.9 million.

There were 17,608 restricted stock units awarded in February 2016. The grant date fair value of the shares awarded was $0.8 million.

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited) [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED)

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



Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
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
2014
Operating Revenue		$296.5		$260.7		$288.9		$290.7
Operating Income		$48.3		$28.2		$60.8		$51.5
Net Income Attributable to ALLETE		$33.5		$16.8		$41.6		$32.9
Earnings Per Share of Common Stock
Basic		$0.81		$0.40		$0.97		$0.73
Diluted		$0.80		$0.40		$0.97		$0.73

Schedule II

12 Months Ended

Dec. 31, 2015

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
2013 Trade Accounts Receivable		$1.0		$1.3	—		$1.2		$1.1
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
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
Deferred Asset Valuation Allowance
2013 Deferred Tax Assets		$2.4	$5.6		—	—			$8.0
2014 Deferred Tax Assets		$8.0	$14.1		—	—			$22.1
2015 Deferred Tax Assets		$22.1		$9.5	—	—			$31.6


(a)	Includes uncollectible accounts written off.

Operations and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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 accounting principles generally accepted in the United States of America. 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.
Reclassifications [Policy Text Block]	As a result of recent acquisitions, certain financial statement captions have been added and we have reclassified certain prior-period amounts on our Consolidated Balance Sheet and Consolidated Statement of Income to conform to the presentation for the current period.
Business Segments [Policy Text Block]	During the year ended December 31, 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess, and allocate resources after our recent acquisitions. We now present three reportable segments, Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Cash and Cash Equivalents [Policy Text Block]	We consider all investments purchased with original maturities of three months or less to be cash equivalents.
Accounts Receivable [Policy Text Block]	Accounts receivable are reported on the Consolidated Balance Sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific 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 9. 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. Amounts removed from inventories in our Regulated Operations and ALLETE Clean Energy segments are recorded on an average cost basis. Amounts removed from inventories in our U.S. Water Services and Corporate and Other segments are recorded on an average cost, first-in, first-out or specific identification basis.
Property, Plant and Equipment [Policy Text Block]	Property, plant and equipment are recorded at original cost and are reported on the 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-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for the effects of certain types of regulation. 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 3. Property, Plant and Equipment. 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]	Land inventory is accounted for as held for use and is recorded at cost or estimated fair value. We review our long-lived assets, which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate 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, which may include a bulk sale of its entire portfolio, the sale of each individual land parcel, combining various parcels, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net cash flows on an undiscounted basis. 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, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel, may vary among each land parcel, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.
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.
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 18. 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. NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued) Performance Shares. Under the performance share awards plan, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies. In the case of qualified retirement, death, or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death, or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined by the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients. Restricted Stock Units. Under the restricted stock units plan, shares for participants eligible for retirement vest monthly over a three-year period. For participants not eligible for retirement, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients. Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards. RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.
Goodwill [Policy Text Block]	Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. To align with the annual budgeting and forecasting process, 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. 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 estimated fair value is generally determined using a discounted cash flow analysis. To align with the annual budgeting and forecasting process, 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. 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.
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 useful lives ranging from approximately 3 years to approximately 22 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. (See Note 12. Commitments, Guarantees and Contingencies.) 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 charged to expense unless recoverable in rates from customers.
Revenue Recognition [Policy Text Block]	Regulated Operations utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for 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 energy and environmental expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. Revenue from our cost recovery riders (renewable resources, transmission 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 our Consolidated Statement of Income and Regulatory Assets on our Consolidated Balance Sheet until it is subsequently collected from customers. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) Revenue Recognition (Continued) 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 our Consolidated Statement of Income. The revenue and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense. ALLETE Clean Energy recognizes revenue from the sale of energy under long-term PPAs. 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 the wind energy facilities acquisitions in 2014 and 2015, ALLETE Clean Energy assumed various PPAs 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. 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.
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. 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 15. Income Tax Expense.) Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on our Consolidated Statement of Income.
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 involves 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 7. Acquisitions.) 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 liabilities assumed at the date of acquisition. Fair value measurements were valued primarily using the replacement cost method and determined that the assets acquired amounted to cash of $3.6 million and construction in process of $23.4 million. 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. 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]	Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. In April 2014, the FASB issued an accounting standard update modifying the criteria for determining which disposals should be presented as discontinued operations and modifying the related disclosure requirements. Additionally, the new guidance requires that a business which qualifies as held for sale upon acquisition should be reported as discontinued operations. The new guidance was effective beginning in the first quarter of 2015, and will be applied prospectively to disposals and classifications of disposal groups as held for sale. The impact of this guidance on our consolidated financial position, results of operations or cash flows will be evaluated when future transactions arise. 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. This accounting guidance was to have been effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. On July 9, 2015, the FASB decided to defer the effective date of the standard by one year which will make the guidance effective for the Company beginning in the first quarter of 2018. Early adoption is permitted beginning in the first quarter of 2017 for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s Consolidated Financial Statements. 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. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The adoption of this update is not expected to 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. Balance Sheet Classification of Deferred Taxes. In November 2015, the FASB issued an accounting standard to simplify the presentation of deferred income taxes. Under the new standard, both deferred tax liabilities and assets are required to be classified as noncurrent instead of separating deferred taxes into current and noncurrent amounts. This accounting guidance is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted. During the fourth quarter of 2015, we elected to prospectively adopt the new standard, reclassifying $39.4 million of current deferred income tax assets to noncurrent deferred income tax liabilities on our Consolidated Balance Sheet for 2015. Previously reported periods have not been adjusted. The adoption of this guidance had no impact on our Consolidated Statement of Income, Consolidated Statement of Comprehensive Income and Consolidated Statement of Cash Flows.
Asset Retirement Obligations [Policy Text Block]	We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our coal-fired and wind energy facilities and land reclamation at BNI Energy, and are included in Other Non-Current Liabilities on our 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. 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 a $36.3 million non-cash impairment was recorded for the year ended December 31, 2015 (none for the years ended December 31, 2014 and 2013).
Fair Value Measurement [Policy Text Block]	The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value is measured based on the consideration expected to be transferred, discounted to present value. The discount rate is 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 our Consolidated Statement of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, or in 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. 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. 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). Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).
Fair Value Transfers [Policy Text Block]	The Company’s policy is to recognize transfers in and transfers out 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.
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 2015, 2014 and 2013.
Pension and Other Postretirement Benefit Plans [Policy Text Block]	Accounting for defined benefit pension and 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 our 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. 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 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 yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation. The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations.
Employee Stock Ownership Plan [Policy Text Block]	According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock held and purchased by the ESOP were treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants. The ESOP shares were initially pledged as collateral for the debt. As the debt was repaid, shares were released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares were released from collateral, we reported compensation expense equal to the current market price of the shares less dividends on allocated shares. The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings.

Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

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	2015		2014		2013
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$59.0		$51.3		$47.5
Cash Paid During the Period for Income Taxes		$0.4		$5.1		$0.5
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(40.6)			$21.7		$8.3
Capitalized Asset Retirement Costs		$12.4		$22.4	$(0.7)
AFUDC–Equity		$3.3		$7.8		$4.6
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	—			$19.5	—
Contingent Consideration		$35.7	—		—

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2015		2014
Millions
Trade Accounts Receivable
Billed		$105.3		$85.5
Unbilled	16.9		18.6
Less: Allowance for Doubtful Accounts	1.0		1.1
Total Accounts Receivable		$121.2		$103.0

Inventories [Table Text Block]



Inventories
As of December 31	2015			2014
Millions
Fuel (a)		$58.1			$29.0
Materials and Supplies	49.1			51.5
Raw Materials	2.7			—
Finished Goods	7.5			—
Reserve for Obsolescence	(0.3		)	—
Total Inventories		$117.1			$80.5


(a)	Fuel consists primarily of coal inventory at Minnesota Power. During 2015, Minnesota Power increased its coal inventory to take advantage of favorable pricing.

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets
As of December 31	2015		2014
Millions
Deferred Fuel Adjustment Clause		$10.6		$16.3
Construction Costs for Development Project (a)	—		48.2
Restricted Cash (b)	5.6		2.7
Other	19.5		14.8
Total Prepayments and Other Current Assets		$35.7		$82.0


(a)	Construction Costs for Development Project related to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)


(b)	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 Current and Non-Current Liabilities [Table Text Block]



Other Current Liabilities
As of December 31	2015		2014
Millions
Customer Deposits		$15.1		$19.7
Power Purchase Agreements (a)	23.3		19.4
Construction Deposits Received for Development Project (b)	—		54.3
Other (c)	47.7		27.4
Total Other Current Liabilities		$86.1		$120.8


(a)	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)


(b)	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)


(c)	Increase in 2015 includes customer refund liabilities of approximately $7 million, pending regulatory approval.



Other Non-Current Liabilities
As of December 31	2015		2014
Millions
Asset Retirement Obligation		$131.4		$109.2
Power Purchase Agreements (a)	138.1		110.7
Contingent Consideration (b)	36.6		—
Other	42.9		45.1
Total Other Non-Current Liabilities		$349.0		$265.0


(a)	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 7. Acquisitions and Note 10. Fair Value.)

Business Segments (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Business Segments [Table Text Block]



As of December 31	2015		2014
Millions
Assets
Regulated Operations	$3,862.6		$3,709.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	504.6		291.9
U.S. Water Services	258.3		—

Corporate and Other	281.6		359.3
Total Assets		$4,907.1		$4,360.8
Capital Expenditures
Regulated Operations	$224.4		$583.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	8.6		4.2
U.S. Water Services	2.9		—

Corporate and Other	15.9		16.6
Total Capital Expenditures		$251.8		$604.3



Year Ended December 31	2015			2014			2013
Millions
Operating Revenue
Regulated Operations		$991.2			$1,003.5			$925.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	262.1			33.2			—
U.S. Water Services	119.8			—			—

Corporate and Other	113.3			100.1			92.9
Total Operating Revenue		$1,486.4			$1,136.8			$1,018.4
Net Income (Loss) Attributable to ALLETE
Regulated Operations (a)		$131.6			$123.0			$103.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	29.9			3.3			(3.4		)
U.S. Water Services	0.9			—			—

Corporate and Other (a)	(21.3		)	(1.5		)	4.5
Total Net Income Attributable to ALLETE		$141.1			$124.8			$104.7
Depreciation and Amortization
Regulated Operations		$135.1			$118.0			$110.2

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

Corporate and Other	8.9			7.6			6.4
Total Depreciation and Amortization		$170.0			$135.7			$116.6
Impairment of Real Estate
Corporate and Other	$36.3			—			—
Interest Expense
Regulated Operations (a)	$53.9			$49.2			$44.4

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

Corporate and Other (a)	8.6			7.1			8.2

Eliminations (a)	(2.3		)	(2.3		)	(2.3		)
Total Interest Expense	$64.9			$54.8			$50.3
Equity Earnings in ATC
Regulated Operations	$16.3			$19.6			$20.3
Income Tax Expense (Benefit)
Regulated Operations		$24.4			$39.0			$35.1

Energy Infrastructure and Related Services
ALLETE Clean Energy	21.0			2.3			(2.3		)
U.S. Water Services	0.9			—			—

Corporate and Other	(21.0		)	(4.6		)	(4.1		)
Total Income Tax Expense		$25.3			$36.7			$28.7


(a)	During 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries. The amounts are eliminated in consolidation. Prior period segment results have been revised to conform to the current presentation as if the intercompany loan existed as of January 1, 2013.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

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



Estimated Useful Lives of Property, Plant and Equipment
Regulated Operations		ALLETE Clean Energy	5 to 44 years
Generation	10 to 50 years	U.S. Water Services	3 to 39 years
Transmission	44 to 67 years	Corporate and Other	3 to 39 years
Distribution	18 to 65 years



Property, Plant and Equipment
As of December 31	2015			2014
Millions
Regulated Operations		$4,336.7			$3,903.3
Construction Work in Progress	101.2			355.4
Accumulated Depreciation	(1,323.8		)	(1,260.2		)
Regulated Operations – Net	3,114.1			2,998.5
ALLETE Clean Energy	467.3			203.7
Construction Work in Progress	4.0			1.3
Accumulated Depreciation	(24.0		)	(8.4		)
ALLETE Clean Energy – Net	447.3			196.6
U.S. Water Services	15.6			—
Accumulated Depreciation	(3.4		)	—
U.S. Water Services – Net	12.2			—
Corporate and Other (a)	165.6			152.5
Construction Work in Progress	4.5			4.6
Accumulated Depreciation	(74.6		)	(67.4		)
Corporate and Other – Net	95.5			89.7
Property, Plant and Equipment – Net		$3,669.1			$3,284.8


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

Asset Retirement Obligations [Table Text Block]



Asset Retirement Obligations
Millions
Obligation as of December 31, 2013		$81.8
Accretion	5.5
Liabilities Recognized (a)	23.0
Liabilities Settled	(0.5		)
Revisions in Estimated Cash Flows	(0.6		)
Obligation as of December 31, 2014	109.2
Accretion	7.3
Liabilities Recognized (b)	5.1
Liabilities Settled	(2.6		)
Revisions in Estimated Cash Flows	12.4
Obligation as of December 31, 2015		$131.4


(a)	The increase in 2014 is related to BNI Energy for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.(See Note 7. Acquisitions.)


(b)	The increase in 2015 is related to the ALLETE Clean Energy wind energy facilities acquisitions in 2015. (See Note 7. Acquisitions.)

Jointly-Owned Facilities and Projects (Tables)

12 Months Ended

Dec. 31, 2015

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 As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
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
2014
Boswell Unit 4		$419.1		$209.1		$168.1	80
CapX2020 Projects	55.5		1.7		44.0		9.3 - 14.7
Total		$474.6		$210.8		$212.1

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]

NOTE 5. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2015		2014
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$10.6		$16.3
Total Current Regulatory Assets	10.6		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	219.3		223.9
Income Taxes (c)	64.2		46.6
Cost Recovery Riders (d)	58.0		59.7
Asset Retirement Obligations (e)	21.6		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	3.9		4.3
Total Non-Current Regulatory Assets	372.0		357.3
Total Regulatory Assets		$382.6		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$58.0		$42.9
Plant Removal Obligations	22.1		22.8
Income Taxes (c)	6.1		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	0.9		3.5
Other	17.9		11.6
Total Non-Current Regulatory Liabilities		$105.0		$94.2


(a)	Current regulatory assets are included in 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.

Investment in ATC (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

ALLETE's Investment in ATC [Table Text Block]



ALLETE’s Investment in ATC
Year Ended December 31	2015			2014
Millions
Equity Investment Beginning Balance		$121.1			$114.6
Cash Investments	1.6			3.9
Equity in ATC Earnings	16.3			19.6
Distributed ATC Earnings	(14.5		)	(17.0		)
Equity Investment Ending Balance		$124.5			$121.1



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2015		2014
Millions
Current Assets		$80.5		$66.4
Non-Current Assets	3,957.6		3,728.7
Total Assets		$4,038.1		$3,795.1
Current Liabilities		$330.3		$313.1
Long-Term Debt	1,800.0		1,701.0
Other Non-Current Liabilities	245.0		163.8
Members’ Equity	1,662.8		1,617.2
Total Liabilities and Members’ Equity		$4,038.1		$3,795.1



Income Statement Data
Year Ended December 31	2015		2014		2013
Millions
Revenue		$615.8		$635.0		$626.3
Operating Expense	319.3		307.4		295.1
Other Expense	96.1		88.9		83.6
Net Income		$200.4		$238.7		$247.6
ALLETE’s Equity in Net Income		$16.3		$19.6		$20.3

Acquisitions Acquisitions (Tables)

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

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 will be 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 will be 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 8. Goodwill and Intangible Assets.)


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



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 Purchase 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 Power Purchase Agreements.



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 Purchase 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 Power Purchase Agreements.



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 Purchase 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 Power Purchase Agreements.


(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.



Millions
Assets Acquired
Current Assets	$1.0
Property, Plant and Equipment	0.1
Intangible Assets (a)	3.9
Goodwill (b)	4.3
Total Assets Acquired		$9.3
Liabilities Assumed
Current Liabilities		$0.1
Total Liabilities Assumed	$0.1
Net Identifiable Assets Acquired		$9.2


(a)	Intangible Assets include customer relationships and non-compete agreements. (See Note 8. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in $4.3 million of deductible goodwill.



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 Power Purchase Agreements 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 Power Purchase Agreements, $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.

Goodwill and Intangible Assets Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

The following table summarizes changes to goodwill by reportable segment for the year ended December 31, 2015:



	ALLETE Clean Energy		U.S. Water Services		Total
Millions
Balance as of December 31, 2014		$2.9	—			$2.9
Acquired Goodwill	0.4			$127.3	127.7
Balance as of December 31, 2015		$3.3		$127.3		$130.6

Schedule of Intangible Assets [Table Text Block]

Balances of intangible assets, net, excluding goodwill as of December 31, 2015, are as follows:



	December 31, 2014		Additions (a)		Amortization	Other (b)	December 31, 2015
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	—			$64.0	$(3.2)	—		$60.8
Developed Technology and Other (c)		$1.9	6.4		(0.8)	$(0.3)	7.2
Total Definite-Lived Intangible Assets	1.9		70.4		(4.0)	(0.3)	68.0
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	—		16.6		n/a	—	16.6
Total Intangible Assets		$1.9		$87.0	$(4.0)	$(0.3)		$84.6


(a)	Additions are primarily the result of the U.S. Water Services acquisition. (See Note 7. Acquisitions.)


(b)	Armenia Mountain was acquired on July 1, 2015, at which time the purchase option intangible asset was reclassified as a component of the acquisition consideration.


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

Investments (Tables)

12 Months Ended

Dec. 31, 2015

Investments [Abstract]

Other Investments [Table Text Block]



Other Investments
As of December 31	2015		2014
Millions
ALLETE Properties (a)		$50.1		$88.2
Available-for-sale Securities (b)	18.5		18.9
Cash Equivalents	2.0		2.9
Other	4.0		4.4
Total Other Investments		$74.6		$114.4


(a)	In 2015, ALLETE Properties recorded a $36.3 million non-cash impairment charge related to its real estate assets. (See Note 1. Operations and Significant Accounting Policies.)


(b)	As of December 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was none, in one year to less than three years was $1.0 million, in three years to less than five years was $3.2 million, and in five or more years was $6.7 million.

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2015	$20.0	—	$1.5	$18.5
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2015		$1.7	$0.1	—
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2015	$20.0	—	$1.5	$18.5
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2015		$1.7	$0.1	—
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—

Fair Value (Tables)

12 Months Ended

Dec. 31, 2015

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, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.1	—		—		$8.1
Available-for-sale – Corporate Debt Securities	—			$10.8	—	10.8
Cash Equivalents	2.9		—		—	2.9
Total Fair Value of Assets		$11.0		$10.8	—		$21.8

Liabilities:
Deferred Compensation (b)	—			$16.2	—		$16.2
Derivatives – Interest Rate Swap (c)	—		0.3		—	0.3
Total Fair Value of Liabilities	—			$16.5	—		$16.5
Total Net Fair Value of Assets (Liabilities)		$11.0	$(5.7)		—		$5.3


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


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


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

Recurring Fair Value 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 Expense (a)	2.4
Changes in Cash Flow Projections	(1.5		)
Balance as of December 31, 2015		$36.6


(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 Current Portion
December 31, 2015	$1,605.0	$1,676.0
December 31, 2014	$1,373.5	$1,484.5

Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Long-term Debt [Table Text Block]



Long-Term Debt
As of December 31	2015		2014
Millions
First Mortgage Bonds
7.70% Series Due 2016	$20.0		$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		—
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		—
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 2015	—		75.0
Unsecured Term Loan Variable Rate Due 2017	125.0		—
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020	13.5		24.6
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	83.3		—
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		15.0
Other Long-Term Debt, 0.08% – 7.45% Due 2016 – 2037	68.4		59.1
Total Long-Term Debt	1,605.0		1,373.5
Less: Due Within One Year	36.3		100.7
Net Long-Term Debt		$1,568.7		$1,272.8

On September 24, 2015, we issued $100.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:



Maturity Date	Principal Amount	Interest Rate
September 15, 2020	$40 Million	2.80%
September 16, 2030	$60 Million	3.86%

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Common Stock and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2015

Common Stock and Earnings Per Share [Abstract]

Summary of Common Stock [Table Text Block]



Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2012	39,377		$784.7
Employee Stock Purchase Program	16	0.7
Invest Direct	395	18.5
Options and Stock Awards	301	17.9
Equity Issuance Program	1,312	63.4
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
Contribution 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	1,413	65.4
Balance as of December 31, 2015	49,075		$1,271.4

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



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
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
2013
Net Income Attributable to ALLETE		$104.7			$104.7
Average Common Shares	39.7		0.1	39.8
Earnings Per Share		$2.64			$2.63

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2015			2014			2013
Millions
Current Tax Expense
Federal (a)	—			$1.1			—
State (a)	$0.2			2.9			$0.1
Total Current Tax Expense	0.2			4.0			0.1
Deferred Tax Expense
Federal	19.4			25.3			22.9
State	6.5			8.2			6.5
Investment Tax Credit Amortization	(0.8		)	(0.8		)	(0.8		)
Total Deferred Tax Expense	25.1			32.7			28.6
Total Income Tax Expense		$25.3			$36.7			$28.7

(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	2015			2014			2013
Millions
Income Before Non-Controlling Interest and Income Taxes		$166.8			$162.2			$133.4
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$58.4			$56.8			$46.7
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	4.4			7.2			4.3
Regulatory Differences for Utility Plant	(0.6		)	(3.5		)	(2.2		)
Production Tax Credits	(37.0		)	(23.7		)	(19.2		)
Other	0.1			(0.1		)	(0.9		)
Total Income Tax Expense		$25.3			$36.7			$28.7

Deferred Tax Assets and Liabilities [Table Text Block]



Deferred Tax Assets and Liabilities
As of December 31	2015			2014
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$105.4			$102.2
Property Related	126.6			102.7
NOL Carryforwards	186.4			156.5
Tax Credit Carryforwards	164.8			95.7
Power Purchase Agreements	73.0			51.8
Other	21.8			17.0
Gross Deferred Tax Assets	678.0			525.9
Deferred Tax Asset Valuation Allowance	(31.6		)	(22.1		)
Total Deferred Tax Assets		$646.4			$503.8
Deferred Tax Liabilities
Property Related		$1,053.0			$848.8
Regulatory Asset for Benefit Obligations	89.4			89.9
Unamortized Investment Tax Credits	26.0			10.3
Partnership Basis Differences	47.8			41.9
Other	10.0			16.1
Total Deferred Tax Liabilities		$1,226.2			$1,007.0
Net Deferred Income Taxes		$579.8			$503.2
Recorded as:
Net Current Deferred Tax Assets (a)	—			$7.5
Net Long-Term Deferred Tax Liabilities		$579.8		510.7
Net Deferred Income Taxes		$579.8			$503.2


(a)	For discussion of classification of deferred income taxes see Note 1. Operations and Significant Accounting Policies - New Accounting Standards - Balance Sheet Classification of Deferred Taxes.



NOL and Tax Credit Carryforwards
As of December 31	2015	2014
Millions
Federal NOL Carryforwards (a)	$493.0		$413.7
Federal Tax Credit Carryforwards	$113.6	$59.3
State NOL Carryforwards (a)	$228.6	$184.7
State Tax Credit Carryforwards (b)	$20.0	$14.7

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
As of December 31	2015	2014
Millions
Federal NOL Carryforwards (a)	$493.0		$413.7
Federal Tax Credit Carryforwards	$113.6	$59.3
State NOL Carryforwards (a)	$228.6	$184.7
State Tax Credit Carryforwards (b)	$20.0	$14.7


(a)	Pretax amounts.


(b)	Net of a $31.2 million valuation allowance as of December 31, 2015 ($21.7 million as of December 31, 2014).

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2015			2014			2013
Millions
Balance at January 1		$2.0			$1.2			$2.7
Additions for Tax Positions Related to the Current Year	0.5			—			0.1
Additions for Tax Positions Related to Prior Years	0.7			1.0			1.3
Reductions for Tax Positions Related to Prior Years	(0.7		)	—			—
Reductions for Settlements	—			—			(2.9		)
Lapse of Statute	(0.1		)	(0.2		)	—
Balance as of December 31		$2.4			$2.0			$1.2

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

12 Months Ended

Dec. 31, 2015

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

Changes in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Changes in accumulated other comprehensive loss, net of tax, for the years ended December 31, 2015, 2014 and 2013, 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, 2012	$(0.1)		$(21.5)		$(0.4)		$(22.0)
Other Comprehensive Income Before Reclassifications	1.3		3.2		0.1		4.6
Amounts Reclassified From Accumulated Other Comprehensive Loss	(1.3	)	1.6		—		0.3
Net Other Comprehensive Income	—		4.8		0.1		4.9
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)


(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 17. Pension and Other Postretirement Benefit Plans.)

Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2016		$39.8		$8.3
2017		$40.6		$8.6
2018		$41.1		$8.8
2019		$41.7		$9.1
2020		$41.8		$9.3
Years 2021 – 2025		$216.2		$48.0

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 (Gain) Loss	$(8.4)	$0.2
Prior Service Credit	—	(2.9)
Total Pension and Postretirement Health and Life Credit	$(8.4)	$(2.7)

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



Assumptions Used to Determine Benefit Obligation
As of December 31	2015	2014
Discount Rate
Pension	4.72%	4.30%
Postretirement Health and Life	4.73%	4.33%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	6.50%	6.75%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2022



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2015	2014	2013
Discount Rate	4.30 - 4.33%	4.93 - 4.96%	4.10 - 4.13%
Expected Long-Term Return on Plan Assets
Pension	8.00%	8.00%	8.25%
Postretirement Health and Life	6.40 - 8.00%	6.40 - 8.00%	6.60 - 8.25%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%	4.30 - 4.60%

Plan Asset Allocations, Actual and Target [Table Text Block]



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)
	2015		2014		2015		2014
Equity Securities	47	%	48	%	57	%	58	%
Debt Securities	39	%	39	%	35	%	34	%
Private Equity	8	%	8	%	8	%	8	%
Real Estate	6	%	5	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Pension Obligation and Funded Status
At December 31	2015			2014
Millions
Accumulated Benefit Obligation		$665.0			$661.4
Change in Benefit Obligation
Obligation, Beginning of Year		$714.5			$622.8
Service Cost	10.1			8.3
Interest Cost	29.9			29.8
Actuarial (Gain) Loss	(31.2		)	72.6
Benefits Paid	(40.2		)	(36.9		)
Participant Contributions	26.7			17.9
Obligation, End of Year		$709.8			$714.5
Change in Plan Assets
Fair Value, Beginning of Year		$544.2			$501.6
Actual Return on Plan Assets	(10.8		)	41.0
Employer Contribution (a)	28.1			38.5
Benefits Paid	(40.2		)	(36.9		)
Fair Value, End of Year		$521.3			$544.2
Funded Status, End of Year	$(188.5)			$(170.3)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.3)			$(1.2)
Non-Current Liabilities	$(187.2)			$(169.1)


(a)	Includes Participant Contributions noted above.

Unrecognized Costs [Table Text Block]



Unrecognized Pension Costs
As of December 31	2015		2014
Millions
Net Loss		$252.7		$250.4
Prior Service Cost	—		0.2
Total Unrecognized Pension Costs		$252.7		$250.6

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Pension Expense
Year Ended December 31	2015			2014			2013
Millions
Service Cost		$10.1			$8.3			$9.9
Interest Cost	29.9			29.8			26.0
Expected Return on Plan Assets	(40.7		)	(38.2		)	(35.2		)
Amortization of Loss	17.9			14.2			21.5
Amortization of Prior Service Cost	0.2			0.3			0.3
Net Pension Expense		$17.4			$14.4			$22.5

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	2015		2014
Millions
Net Loss	$20.2		$69.8
Amortization of Prior Service Cost	(0.2	)	(0.3	)
Amortization of Loss	(17.9	)	(14.2	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$2.1		$55.3

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



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2015		2014
Millions
Projected Benefit Obligation		$709.8		$714.5
Accumulated Benefit Obligation		$665.0		$661.4
Fair Value of Plan Assets		$521.3		$544.2

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$56.4	—			$88.5
U.S. Mid-cap Growth (a)	13.6		23.9		—		37.5
U.S. Small-cap (a)	13.9		24.4		—		38.3
International	46.1		45.9		—		92.0
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		201.0		—		203.7
Cash and Cash Equivalents	11.9		—		—		11.9
Other Types of Investments:
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$120.4		$351.6		$72.2		$544.2

(a)



	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
Other Types of Investments:
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)

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, 2013		$46.8			$26.5
Actual Return on Plan Assets	1.2			2.8
Purchases, Sales, and Settlements – Net	(4.7		)	(0.4		)
Balance as of December 31, 2014		$43.3			$28.9



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

Postretirement Health and Life [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Postretirement Health and Life Obligation and Funded Status
At December 31	2015			2014
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$170.9			$151.9
Service Cost	4.3			3.4
Interest Cost	7.2			7.3
Actuarial (Gain) Loss	(14.4		)	18.1
Benefits Paid	(10.7		)	(8.9		)
Participant Contributions	2.9			2.6
Plan Amendments	—			(2.9		)
Plan Curtailments	—			(0.6		)
Obligation, End of Year		$160.2			$170.9
Change in Plan Assets
Fair Value, Beginning of Year		$163.2			$157.0
Actual Return on Plan Assets	(3.5		)	11.6
Employer Contribution	1.5			1.1
Participant Contributions	2.9			2.6
Benefits Paid	(10.7		)	(9.1		)
Fair Value, End of Year		$153.4			$163.2
Funded Status, End of Year	$(6.8)			$(7.7)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$6.4			$6.6
Current Liabilities	$(1.0)			$(0.9)
Non-Current Liabilities	$(12.2)			$(13.4)

Unrecognized Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
As of December 31	2015		2014
Millions
Net Loss	$6.5		$6.9
Prior Service Credit	(7.6	)	(10.6	)
Total Unrecognized Postretirement Health and Life Credit	$(1.1)		$(3.7)

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2015			2014			2013
Millions
Service Cost		$4.3			$3.4			$3.9
Interest Cost	7.2			7.3			6.8
Expected Return on Plan Assets	(10.9		)	(10.3		)	(9.7		)
Amortization of Loss	0.4			0.5			1.6
Amortization of Prior Service Credit	(3.0		)	(2.5		)	(2.5		)
Effect of Plan Settlement (a)	—			—			(1.6		)
Net Postretirement Health and Life Credit	$(2.0)			$(1.6)			$(1.5)


(a)	Result of the termination of a legacy benefit plan.

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	2015			2014
Millions
Net Loss	—			$16.4
Prior Service Credit Arising During the Period	—			(3.0	)
Amortization of Prior Service Credit		$3.0		2.5
Amortization of Loss	(0.4		)	(0.5	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$2.6			$15.4

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates [Table Text Block]



Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.9	$(1.5)
Effect on Postretirement Health and Life Obligation		$19.3	$(15.9)

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)		$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
Other Types of Investments:
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).



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$29.3	—		—			$29.3
U.S. Mid-cap Growth (a)	20.0		—		—		20.0
U.S. Small-cap (a)	12.6		—		—		12.6
International	30.6		—		—		30.6
Debt Securities:
Mutual Funds	44.5		—		—		44.5
Fixed Income	—			$9.9	—		9.9
Cash and Cash Equivalents	3.4		—		—		3.4
Other Types of Investments:
Private Equity Funds	—		—			$12.9	12.9
Total Fair Value of Assets		$140.4		$9.9		$12.9		$163.2


(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, 2013		$13.1
Actual Return on Plan Assets	1.4
Purchases, Sales, and Settlements – Net	(1.6		)
Balance as of December 31, 2014		$12.9



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

Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2015

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

Employee Stock Ownership Plan [Table Text Block]



As of December 31	2015	2014		2013
Millions
ESOP Shares
Allocated	1.8	1.9		2.0
Unallocated	—	0.3		0.5
Total	1.8	2.2		2.5
Fair Value of Unallocated Shares	—		$13.2		$24.1

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	2015		2014		2013
Millions
Performance Shares		$1.8		$1.6		$1.7
Restricted Stock Units	0.8		0.7		0.7
Total Share-Based Compensation Expense		$2.6		$2.3		$2.4
Income Tax Benefit		$1.1		$1.0		$1.0

Non-Qualified Stock Options [Table Text Block]

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



	2015				2014				2013
	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	66,279			$44.39	108,299			$44.10	395,678			$42.28
Granted (a)	—		—		—		—		—		—
Exercised	(24,456	)		$44.52	(42,020	)		$43.65	(287,379	)		$41.60
Forfeited	(2,169	)	$42.93		—		—		—		—
Outstanding as of December 31	39,654			$44.39	66,279			$44.39	108,299			$44.10
Exercisable as of December 31	39,654			$44.39	66,279			$44.39	108,299			$43.17


(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, 2015	$39.10		$44.15		$48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	16,620		2,306		20,728
Weighted Average Remaining Contractual Life (Years)	2.1		0.1		1.1
Weighted Average Exercise Price		$39.10		$44.15		$48.65
Aggregate Intrinsic Value (Millions)		$0.2	—			$0.1

Performance Shares [Table Text Block]

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



	2015				2014				2013
	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	119,635			$48.26	114,765			$47.02	107,899			$40.73
Granted (a)	43,583			$58.95	47,992			$46.47	45,830			$52.15
Awarded	—		—		(36,515	)		$42.01	(18,605	)		$35.10
Unearned Grant Award	(36,670	)		$45.41	—		—		(18,606	)		$35.10
Forfeited	(7,008	)		$53.49	(6,607	)		$48.29	(1,753	)		$47.26
Non-vested as of December 31	119,540			$52.72	119,635			$48.26	114,765			$47.02

(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.



	2015				2014				2013
	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	53,888			$44.47	55,982			$40.85	56,415			$36.61
Granted (a)	26,702			$54.81	19,645			$48.44	21,440			$43.41
Awarded	(19,464	)		$41.44	(18,860	)		$37.64	(20,939	)		$32.03
Forfeited	(3,432	)		$51.52	(2,879	)		$45.92	(934	)		$41.02
Available as of December 31	57,694			$49.86	53,888			$44.47	55,982			$40.85

(a) Shares granted include accrued dividends.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited) [Table Text Block]



Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
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
2014
Operating Revenue		$296.5		$260.7		$288.9		$290.7
Operating Income		$48.3		$28.2		$60.8		$51.5
Net Income Attributable to ALLETE		$33.5		$16.8		$41.6		$32.9
Earnings Per Share of Common Stock
Basic		$0.81		$0.40		$0.97		$0.73
Diluted		$0.80		$0.40		$0.97		$0.73

Operations and Significant Accounting Policies - Reclassifications (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Operating and Maintenance Expense to Cost of Sales [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	$ 77.9	$ 71.2
Operating and Maintenance Expense to Transmission Services [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	45.6	32.3
Operating and Maintenance Expense to Taxes Other than Income Taxes [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	45.6	41.7
Operating Income [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	0.0	0.0
Net Income [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	0.0	0.0
Net Income Attributable to ALLETE [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	0.0	$ 0.0
Property, Plant and Equipment - Net to Goodwill and Intangible Assets - Net [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	1.6
Other Non-Current Assets to Goodwill and Intangible Assets - Net [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	3.2
Total Assets [Member]
Schedule of Prior Period Reclassifications [Line Items]
Prior Period Reclassification	$ 0.0

Operations and Significant Accounting Policies - Business Segments (Details)	12 Months Ended
	Dec. 31, 2015 a Customers 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 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]
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]
Business Segments [Line Items]
Generating Capacity (MW) \| MW	535
Generating Capacity Constructed and Sold (MW) \| MW	107
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 - Balance Sheet and Income Statement Disclosures (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Trade Accounts Receivable [Abstract]

Billed

$ 105.3

$ 85.5

Unbilled

16.9

18.6

Less: Allowance for Doubtful Accounts

1.0

1.1

Total Accounts Receivable

121.2

103.0

Inventories [Abstract]

Fuel

^[1]

58.1

29.0

Materials and Supplies

49.1

51.5

Raw Materials

2.7

0.0

Finished Goods

7.5

0.0

Reserve for Obsolescence

(0.3)

0.0

Total Inventories

117.1

80.5

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

10.6

16.3

Construction Costs for Development Project

^[2]

0.0

48.2

Restricted Cash

^[3]

5.6

2.7

Other Assets

19.5

14.8

Total Prepayments and Other Current Assets

35.7

82.0

Property, Plant and Equipment [Line Items]

Remaining Net Book Value

3,669.1

3,284.8

Impairment of Long-Lived Assets [Abstract]

Total Carrying Value of Real Estate Assets Before Impairment Charge

83.3

Impairment of Real Estate

36.3

0.0

$ 0.0

Other Non-Current Assets [Abstract]

Restricted Cash

8.1

5.3

Other Current Liabilities [Abstract]

Customer Deposits

15.1

19.7

Power Purchase Agreements

^[4]

23.3

19.4

Construction Deposits Received for Development Project

^[5]

0.0

54.3

Other

47.7

^[6]

27.4

Total Other Current Liabilities

86.1

120.8

Customer Refund Liabilities

7.0

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

131.4

109.2

Power Purchase Agreements

^[7]

138.1

110.7

Contingent Consideration

^[8]

36.6

0.0

Other

42.9

45.1

Total Other Non-Current Liabilities

349.0

265.0

Business Segments [Line Items]

Amortization of Power Purchase Agreements

$ 23.2

12.7

0.0

Income Taxes [Abstract]

More-Likely-Than-Not Percentage

50.00%

Current Deferred Income Tax Assets Reclassified to Non-Current Deferred Income Tax Liabilities

$ 39.4

Regulated Operations [Member]

Prepayments and Other Current Assets [Abstract]

Construction Costs for Development Project

101.2

355.4

Property, Plant and Equipment [Line Items]

Remaining Net Book Value

$ 3,114.1

2,998.5

Business Segments [Line Items]

Alternative Revenue Program, Required Collection Period

24 months

ALLETE Clean Energy [Member]

Prepayments and Other Current Assets [Abstract]

Construction Costs for Development Project

$ 4.0

1.3

Property, Plant and Equipment [Line Items]

Remaining Net Book Value

447.3

196.6

Business Segments [Line Items]

Amortization of Power Purchase Agreements

23.2

12.7

Corporate and Other [Member]

Prepayments and Other Current Assets [Abstract]

Construction Costs for Development Project

4.5

4.6

Property, Plant and Equipment [Line Items]

Remaining Net Book Value

95.5

89.7

Impairment of Long-Lived Assets [Abstract]

Impairment of Real Estate

$ 36.3

$ 0.0

Business Segments [Line Items]

Minimum Cash Collections Requirement for Real Estate Sales (Percent)

20.00%

Minimum [Member]

Definite-Lived Intangible Assets [Line Items]

Useful Life (Years)

3 years

Maximum [Member]

Definite-Lived Intangible Assets [Line Items]

Useful Life (Years)

22 years

Taconite Harbor [Member]

Property, Plant and Equipment [Line Items]

Remaining Net Book Value

$ 100.0

[1]	Fuel consists primarily of coal inventory at Minnesota Power. During 2015, Minnesota Power increased its coal inventory to take advantage of favorable pricing.
[2]	Construction Costs for Development Project related to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)
[3]	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.
[4]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[5]	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)
[6]	Increase in 2015 includes customer refund liabilities of approximately $7 million, pending regulatory approval.
[7]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[8]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 7. Acquisitions and Note 10. Fair Value.)

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$ 59.0	$ 51.3	$ 47.5
Cash Paid During the Period for Income Taxes	0.4	5.1	0.5
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	(40.6)
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		21.7	8.3
Capitalized Asset Retirement Costs	12.4	22.4	(0.7)
AFUDC–Equity	3.3	7.8	4.6
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	0.0	19.5	0.0
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed	$ 35.7	$ 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, 2015 USD ($) Customers	Dec. 31, 2014 USD ($)	Dec. 31, 2013
Concentration Risk [Line Items]
Number of Customers	9
Accounts Receivable \| $	$ 9.2	$ 14.7
Largest Customer [Member]
Concentration Risk [Line Items]
Number of Customers	1
Largest Customer [Member] \| Consolidated Operating Revenue [Member]
Concentration Risk [Line Items]
Major Customer, Percent of Consolidated Revenue	7.70%	11.90%	12.00%

Business Segments (Details) $ in Millions	3 Months Ended								12 Months Ended
Business Segments (Details) $ in Millions	Dec. 31, 2015 USD ($) a	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) a	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Business Segments [Line Items]
Description of Effect on Previously Reported Segment Information for Change in Composition of Reportable Segments									During the year ended December 31, 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess, and allocate resources after our recent acquisitions. We now present three reportable segments, Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. Prior period amounts have been revised to conform with the current business segment presentation.
Number of Reportable Segments									3
Operating Revenue	$ 380.6	$ 462.5	$ 323.3	$ 320.0	$ 290.7	$ 288.9	$ 260.7	$ 296.5	$ 1,486.4	$ 1,136.8	$ 1,018.4
Net Income (Loss) Attributable to Parent	18.3	$ 60.4	$ 22.5	$ 39.9	32.9	$ 41.6	$ 16.8	$ 33.5	141.1	124.8	104.7
Depreciation and Amortization									170.0	135.7	116.6
Impairment of Real Estate									36.3	0.0	0.0
Interest Expense									64.9	54.8	50.3
Equity Earnings in ATC									16.3	19.6	20.3
Income Tax Expense (Benefit)									25.3	36.7	28.7
Assets	4,907.1				4,360.8				4,907.1	4,360.8
Capital Expenditures									$ 251.8	604.3
Regulated Operations [Member]
Business Segments [Line Items]
Number of Operating Segments									3
Operating Revenue									$ 991.2	1,003.5	925.5
Net Income (Loss) Attributable to Parent									131.6	123.0	103.6
Depreciation and Amortization									135.1	118.0	110.2
Interest Expense									53.9	49.2	44.4
Equity Earnings in ATC									16.3	19.6	20.3
Income Tax Expense (Benefit)									24.4	39.0	35.1
Assets	3,862.6				3,709.6				3,862.6	3,709.6
Capital Expenditures									224.4	583.5
ALLETE Clean Energy [Member]
Business Segments [Line Items]
Operating Revenue									262.1	33.2	0.0
Net Income (Loss) Attributable to Parent									29.9	3.3	(3.4)
Depreciation and Amortization									18.7	10.1	0.0
Interest Expense									3.3	0.8	0.0
Income Tax Expense (Benefit)									21.0	2.3	(2.3)
Assets	504.6				291.9				504.6	291.9
Capital Expenditures									8.6	4.2
U.S. Water Services [Member]
Business Segments [Line Items]
Operating Revenue									119.8	0.0	0.0
Net Income (Loss) Attributable to Parent									0.9	0.0	0.0
Depreciation and Amortization									7.3	0.0	0.0
Interest Expense									1.4	0.0	0.0
Income Tax Expense (Benefit)									0.9	0.0	0.0
Assets	$ 258.3				0.0				258.3	0.0
Capital Expenditures									$ 2.9	0.0
Corporate and Other [Member]
Business Segments [Line Items]
Number of Operating Segments									2
Land in Minnesota (Acres) \| a	5,000								5,000
Operating Revenue									$ 113.3	100.1	92.9
Net Income (Loss) Attributable to Parent									(21.3)	(1.5)	4.5
Depreciation and Amortization									8.9	7.6	6.4
Impairment of Real Estate									36.3	0.0	0.0
Interest Expense									8.6	7.1	8.2
Income Tax Expense (Benefit)									(21.0)	(4.6)	(4.1)
Assets	$ 281.6				$ 359.3				281.6	359.3
Capital Expenditures									15.9	16.6
Eliminations [Member]
Business Segments [Line Items]
Interest Expense									$ (2.3)	$ (2.3)	$ (2.3)

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Property, Plant and Equipment [Line Items]

Construction Work in Progress

^[1]

$ 0.0

$ 48.2

Property, Plant and Equipment – Net

3,669.1

3,284.8

Asset Retirement Obligation [Roll Forward]

Beginning Obligation

109.2

81.8

Accretion

7.3

5.5

Liabilities Recognized

5.1

^[2]

23.0

^[3]

Liabilities Settled

(2.6)

(0.5)

Revisions in Estimated Cash Flows

12.4

(0.6)

Ending Obligation

131.4

109.2

Regulated Operations [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment

4,336.7

3,903.3

Construction Work in Progress

101.2

355.4

Accumulated Depreciation

(1,323.8)

(1,260.2)

Property, Plant and Equipment – Net

$ 3,114.1

2,998.5

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

10 years

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

50 years

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

44 years

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

67 years

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

18 years

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

65 years

ALLETE Clean Energy [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment

$ 467.3

203.7

Construction Work in Progress

4.0

1.3

Accumulated Depreciation

(24.0)

(8.4)

Property, Plant and Equipment – Net

$ 447.3

196.6

ALLETE Clean Energy [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

5 years

ALLETE Clean Energy [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

44 years

U.S. Water Services [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment

$ 15.6

0.0

Accumulated Depreciation

(3.4)

0.0

Property, Plant and Equipment – Net

$ 12.2

0.0

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

3 years

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

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

39 years

Corporate and Other [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment

^[4]

$ 165.6

152.5

Construction Work in Progress

4.5

4.6

Accumulated Depreciation

(74.6)

(67.4)

Property, Plant and Equipment – Net

$ 95.5

$ 89.7

Corporate and Other [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

3 years

Corporate and Other [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

39 years

[1]	Construction Costs for Development Project related to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)
[2]	The increase in 2015 is related to the ALLETE Clean Energy wind energy facilities acquisitions in 2015. (See Note 7. Acquisitions.)
[3]	The increase in 2014 is related to BNI Energy for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.(See Note 7. Acquisitions.)
[4]	Primarily includes BNI Energy and a small amount of non-rate base generation.

Jointly-Owned Facilities and Projects (Details) $ in Millions	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014 USD ($)
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 769.3	$ 474.6
Accumulated Depreciation	198.4	210.8
Construction Work in Progress	$ 6.9	212.1
CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	3
Completed Project - Prior Years [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	2
Transmission [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 101.1	55.5
Accumulated Depreciation	3.4	1.7
Construction Work in Progress	$ 0.0	$ 44.0
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%
Transmission [Member] \| Completed Project - Current Year [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	1
Transmission [Member] \| Completed Project - Prior Years [Member] \| CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	2
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	$ 668.2	$ 419.1
Accumulated Depreciation	195.0	209.1
Construction Work in Progress	$ 6.9	$ 168.1

Regulatory Matters - Utility Rates (Details) $ in Millions			12 Months Ended
Regulatory Matters - Utility Rates (Details) $ in Millions	Jan. 01, 2013	Jun. 01, 2011	Dec. 31, 2015 USD ($) Customers Years MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Minnesota Power [Member] \| Bison Wind Energy Center [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW) \| MW			497
PSCW [Member] \| 2012 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate of Return on Common Equity	10.90%
Electric Rates [Member] \| MPUC [Member] \| 2010 Minnesota Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate of Return on Common Equity		10.38%
Approved Percentage of Capital Structure Related to Equity		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 \| $			$ 86.0	$ 69.9	$ 40.5
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 \| $			$ 700.0
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member]
Regulatory Matters [Line Items]
Number of Customers			16
Length of 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			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			1
Generating Capacity (MW) \| MW			29

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - Integrated Resource Plan [Member] - Natural Gas-Fired [Member] - Minnesota Power [Member]	Dec. 31, 2015 MW
Minimum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	200
Maximum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	300

Regulatory Matters - Boswell Mercury Emission Reduction Plan (Details) - Boswell Unit 4 [Member] $ in Millions	Dec. 31, 2015 USD ($)
Regulatory Matters [Line Items]
Total Project Costs	$ 220
MPUC [Member] \| Boswell Mercury Emissions Reduction Plan [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Total Project Costs	$ 220

Regulatory Matters - Great Northern Transmission Line (GNTL) (Details) - Great Northern Transmission Line [Member]	Dec. 31, 2015 Miles kV
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulatory Matters [Line Items]
Energy CIP Spending Requirement	1.50%
Annual Energy-Savings Goal	1.50%
CIP Triennial Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Investment Goal	$ 7.1	$ 6.9	$ 6.0
Actual Spending	6.6	7.2	6.4
CIP Annual Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Financial Incentive	$ 6.2	$ 8.7	$ 7.1

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member] $ in Millions	Dec. 31, 2015 USD ($)
Return on Equity Complaint 1 [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	9.15%
Return on Equity Complaint 2 [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	8.67%
Return on Equity Complaints [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	10.32%
Return on Equity Complaints [Member] \| Minnesota Power [Member]
Loss Contingencies [Line Items]
Estimated Refund Obligation for MISO Revenue	$ 7.2
Estimated Refund for MISO Transmission Expense	4.5
Reserve	2.7
Reserve, Portion Attributable to Prior Years	$ 1.5

Regulatory Matters - Minnesota Solar Energy Standard (Details) - MPUC [Member]	Dec. 31, 2015 MW
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 Projects	2
Solar Energy Standard Mandate, Percentage of Overall Mandate Expected to be Met with Current Filings or Projects	33.00%
Solar Energy Standard Mandate, Percentage of Small Scale Solar Mandate Expected to be Met with Current Filings or Projects	25.00%
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 [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	1

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Regulatory Assets and Liabilities [Line Items]

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

Current Regulatory Asset

$ 10.6

$ 16.3

Non-Current Regulatory Asset

372.0

357.3

Total Regulatory Assets

382.6

373.6

Non-Current Regulatory Liability

105.0

94.2

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

^[1]

58.0

42.9

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

22.1

22.8

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

^[2]

6.1

13.4

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

^[3]

0.9

3.5

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

17.9

11.6

Deferred Fuel Adjustment Clause [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Asset

^[4]

10.6

16.3

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

^[3]

219.3

223.9

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

^[2]

64.2

46.6

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

^[5]

58.0

59.7

Asset Retirement Obligation [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

^[6]

21.6

17.8

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

5.0

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

$ 3.9

$ 4.3

[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]	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.
[3]	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 17. Pension and Other Postretirement Benefit Plans.)
[4]	Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
[5]	The cost recovery rider regulatory assets are revenues not yet collected from our customers primarily due to capital expenditures related to the Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.
[6]	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.

Investment in ATC (Details) - USD ($) $ in Millions		12 Months Ended
Investment in ATC (Details) - USD ($) $ in Millions	Jan. 29, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance		$ 121.1
Cash Investments		1.6	$ 3.9	$ 3.1
Equity Earnings in ATC		16.3	19.6	20.3
Equity Investment Ending Balance		124.5	121.1
Income Statement Data [Abstract]
ALLETE's Equity in Net Income		$ 16.3	19.6	20.3
ATC [Member]
Investment in ATC [Line Items]
Ownership Percentage		8.00%
Expected Additional Investment in 2016		$ 6.2
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance		121.1	114.6
Cash Investments		1.6	3.9
Equity Earnings in ATC		16.3	19.6	20.3
Distributed ATC Earnings		(14.5)	(17.0)
Equity Investment Ending Balance		124.5	121.1	114.6
Balance Sheet Data [Abstract]
Current Assets		80.5	66.4
Non-Current Assets		3,957.6	3,728.7
Total Assets		4,038.1	3,795.1
Current Liabilities		330.3	313.1
Long-Term Debt		1,800.0	1,701.0
Other Non-Current Liabilities		245.0	163.8
Members' Equity		1,662.8	1,617.2
Total Liabilities and Members' Equity		4,038.1	3,795.1
Income Statement Data [Abstract]
Revenue		615.8	635.0	626.3
Operating Expense		319.3	307.4	295.1
Other Expense		96.1	88.9	83.6
Net Income		200.4	238.7	247.6
ALLETE's Equity in Net Income		$ 16.3	$ 19.6	$ 20.3
ATC [Member] \| Subsequent Event [Member]
ALLETE's Investment in ATC [Roll Forward]
Cash Investments	$ 1.2

Investment in ATC - FERC Complaint (Details) $ in Millions	12 Months Ended
Investment in ATC - FERC Complaint (Details) $ in Millions	Dec. 31, 2015 USD ($)
Return on Equity Complaint 1 [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	9.15%
Return on Equity Complaint 2 [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	8.67%
ATC [Member]
Loss Contingencies [Line Items]
Approved Return on Common Equity	12.20%
Sensitivity Analysis [Member] \| ATC [Member]
Sensitivity Analysis [Line Items]
Basis Point Reduction on Approved Rate of Return on Common Equity	50
Sensitivity Analysis [Member] \| ATC [Member] \| After-tax [Member]
Sensitivity Analysis [Line Items]
Annual Effect on Future Equity Earnings in ATC	$ 0.5
Sensitivity Analysis [Member] \| ATC [Member] \| Pre-tax [Member]
Sensitivity Analysis [Line Items]
Annual Effect on Future Equity Earnings in ATC	0.9
ALLETE Transmission Holdings [Member] \| ATC [Member]
Loss Contingencies [Line Items]
Reserve Reflected in Equity Earnings in ATC	5.2
Reserve Reflected in Equity Earnings in ATC, Portion Attributable to Prior Years	$ 2.4

Acquisitions Acquisitions (Details)	12 Months Ended
Acquisitions Acquisitions (Details)	Dec. 31, 2015	Dec. 31, 2014
Business Combinations [Abstract]
Reason for Business Acquisitions	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 - U.S. Water Services (Details) - USD ($)
$ in Millions

12 Months Ended

Feb. 10, 2015

Dec. 31, 2015

Dec. 31, 2014

Assets Acquired [Abstract]

Goodwill

$ 130.6

$ 2.9

Liabilities Assumed [Abstract]

Restricted Cash - Current

^[1]

$ 5.6

$ 2.7

U.S. Water Services [Member]

Business Acquisition [Line Items]

Date of Acquisition

Feb. 10, 2015

Name of Acquired Entity

U.S. Water Services

Consideration Transferred

$ 202.3

Payments to Acquire Business

166.6

Contingent Consideration

$ 35.7

Percent of Results of Operations Reflected in Income Statement

100.00%

Percentage of Voting Interests Acquired

100.00%

Assets Acquired [Abstract]

Cash and Cash Equivalents

$ 0.9

Accounts Receivable

16.8

Inventories

^[2]

13.4

Other Current Assets

^[3]

5.3

Property, Plant and Equipment

10.6

Intangible Assets

^[4]

83.0

Goodwill

^[5]

122.9

Other Non-Current Assets

0.2

Total Assets Acquired

253.1

Liabilities Assumed [Abstract]

Current Liabilities

19.2

Non-Current Liabilities

31.6

Total Liabilities Assumed

50.8

Net Identifiable Assets Acquired

202.3

Fair Value Adjustments for Work in Progress and Finished Goods Inventories

2.7

Fair Value of Sales Backlog

1.6

Restricted Cash - Current

2.1

Deductible Goodwill

$ 2.9

Acquisition-Related Costs

$ 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 will be 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 will be 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 8. 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

12 Months Ended

Apr. 15, 2015

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Liabilities Assumed [Abstract]

Power Purchase Agreements - Non-Current Liability

^[1]

$ 138.1

$ 110.7

Goodwill

130.6

2.9

Power Purchase Agreements - Current Liability

^[2]

23.3

$ 19.4

Chanarambie/Viking [Member]

Business Acquisition [Line Items]

Date of Acquisition

Apr. 15, 2015

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Chanarambie/Viking

Payments to Acquire Business

$ 48.0

Generating Capacity (MW) | MW

97.5

Assets Acquired [Abstract]

Current Assets

$ 4.8

Property, Plant and Equipment

103.0

Other Non-Current Assets

^[3]

1.0

Total Assets Acquired

108.8

Liabilities Assumed [Abstract]

Current Liabilities

^[4]

6.7

Power Purchase Agreements - Non-Current Liability

49.0

Non-Current Liabilities

5.1

Total Liabilities Assumed

60.8

Net Identifiable Assets Acquired

48.0

Goodwill

0.3

Deductible Goodwill

0.0

Power Purchase Agreements - Current Liability

$ 5.9

Acquisition-Related Costs

$ 0.2

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

Business Acquisition [Line Items]

Generating Capacity (MW) | MW

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

Business Acquisition [Line Items]

Generating Capacity (MW) | MW

85.5

[1]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[2]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[3]	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.
[4]	Current Liabilities included $5.9 million related to the current portion of Power Purchase Agreements.

Acquisitions - Armenia Mountain (Details)
$ in Millions

12 Months Ended

Jul. 01, 2015

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Liabilities Assumed [Abstract]

Restricted Cash - Current

^[1]

$ 5.6

$ 2.7

Restricted Cash - Non-Current

8.1

$ 5.3

Armenia Mountain [Member]

Business Acquisition [Line Items]

Date of Acquisition

Jul. 01, 2015

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Armenia Mountain

Payments to Acquire Business

$ 111.1

Generating Capacity (MW) | MW

100.5

Assets Acquired [Abstract]

Current Assets

^[2]

$ 9.0

Property, Plant and Equipment

156.2

Other Non-Current Assets

^[3]

14.4

Total Assets Acquired

179.6

Liabilities Assumed [Abstract]

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

Power Purchase Agreements - Current Asset

1.0

Restricted Cash - Current

6.0

Power Purchase Agreements - Non-Current Asset

8.2

Restricted Cash - Non-Current

$ 6.1

Goodwill

immaterial

Deductible Goodwill

$ 0.0

Acquisition-Related Costs

$ 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]	Included in Current Assets was $1.0 million related to the current portion of Power Purchase Agreements and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.
[3]	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of Power Purchase Agreements, $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

12 Months Ended

Nov. 01, 2015

Dec. 31, 2015

Dec. 31, 2014

Assets Acquired [Abstract]

Goodwill

$ 130.6

$ 2.9

A and W Technologies [Member]

Business Acquisition [Line Items]

Date of Acquisition

Nov. 01, 2015

Percentage of Voting Interests Acquired

100.00%

Consideration Transferred

$ 9.2

Payments to Acquire Business

8.2

Payment Due in April 2016

1.0

Assets Acquired [Abstract]

Current Assets

1.0

Property, Plant and Equipment

0.1

Intangible Assets

^[1]

3.9

Goodwill

^[2]

4.3

Total Assets Acquired

9.3

Liabilities Assumed [Abstract]

Current Liabilities

0.1

Total Liabilities Assumed

0.1

Net Identifiable Assets Acquired

9.2

Deductible Goodwill

$ 4.3

Acquisition-Related Costs

immaterial

[1]	Intangible Assets include customer relationships and non-compete agreements. (See Note 8. Goodwill and Intangible Assets.)
[2]	For tax purposes, the purchase price allocation resulted in $4.3 million of deductible goodwill.

Acquisitions - Wind Construction Project (Details)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Nov. 30, 2014

USD ($)

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Jun. 30, 2014

USD ($)

Mar. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Business Acquisition [Line Items]

Revenue

$ 380.6

$ 462.5

$ 323.3

$ 320.0

$ 290.7

$ 288.9

$ 260.7

$ 296.5

$ 1,486.4

$ 1,136.8

$ 1,018.4

Assets Acquired [Abstract]

Construction Work in Progress

^[1]

0.0

48.2

0.0

48.2

Goodwill

130.6

2.9

130.6

2.9

Liabilities Assumed [Abstract]

Cost of Sales

302.3

77.9

$ 71.2

Contract Billings

^[2]

$ 0.0

54.3

0.0

54.3

Wind Construction Project [Member]

Business Acquisition [Line Items]

Date of Acquisition

November 2014

Payments to Acquire Business

$ 27.0

Generating Capacity (MW) | MW

107

Number of Wind Turbines

Revenue

197.7

Assets Acquired [Abstract]

Cash and Cash Equivalents

$ 3.6

Construction Work in Progress

23.4

48.2

Goodwill

0.0

Liabilities Assumed [Abstract]

Total Liabilities Assumed

$ 0.0

Cost of Sales

$ 162.9

Contract Billings

$ 54.3

[1]	Construction Costs for Development Project related to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)
[2]	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to construct a wind energy facility which was sold in 2015. (See Note 7. Acquisitions.)

Acquisitions - ACE Wind (Details)
$ in Millions

1 Months Ended

12 Months Ended

Feb. 28, 2014

USD ($)

Jan. 31, 2014

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

Liabilities Assumed [Abstract]

Power Purchase Agreements - Non-Current Liability

^[1]

$ 110.7

$ 138.1

Goodwill

2.9

130.6

Power Purchase Agreements - Current Liability

^[2]

19.4

$ 23.3

Armenia Mountain [Member]

Liabilities Assumed [Abstract]

Purchase Option

$ 0.3

ACE Wind [Member]

Business Acquisition [Line Items]

Date of Acquisition

January 2014

Payments to Acquire Businesses

$ 26.9

Number of Wind Energy Facilities Acquired

Assets Acquired [Abstract]

Cash and Cash Equivalents

$ 3.8

Other Current Assets

14.3

Property, Plant and Equipment

156.9

Other Non-Current Assets

^[3]

7.5

Total Assets Acquired

182.5

Liabilities Assumed [Abstract]

Current Liabilities

^[4]

15.2

Long-Term Debt Due Within One Year

2.2

Long-Term Debt

21.1

Power Purchase Agreements - Non-Current Liability

99.4

Other Non-Current Liabilities

10.6

Non-Controlling Interest

^[5]

7.1

Total Liabilities and Non-Controlling Interest Assumed

155.6

Net Identifiable Assets Acquired

26.9

Goodwill

2.9

Deductible Goodwill

0.0

Power Purchase Agreements - Current Liability

$ 12.4

Acquisition-Related Costs

$ 1.4

Purchase of Non-Controlling Interest

$ 6.0

Storm Lake II [Member]

Business Acquisition [Line Items]

Name of Acquired Entity

Storm Lake II

Generating Capacity (MW) | MW

Lake Benton [Member]

Business Acquisition [Line Items]

Name of Acquired Entity

Lake Benton

Generating Capacity (MW) | MW

104

Condon [Member]

Business Acquisition [Line Items]

Name of Acquired Entity

Condon

Generating Capacity (MW) | MW

[1]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[2]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[3]	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.
[4]	Current Liabilities included $12.4 million related to the current portion of Power Purchase Agreements.
[5]	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

1 Months Ended

12 Months Ended

Dec. 31, 2014

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

Liabilities Assumed [Abstract]

Power Purchase Agreements - Non-Current Liability

^[1]

$ 110.7

$ 138.1

Restricted Cash - Non-Current

5.3

8.1

Power Purchase Agreements - Current Liability

^[2]

$ 19.4

$ 23.3

Storm Lake I [Member]

Business Acquisition [Line Items]

Date of Acquisition

December 2014

Name of Acquired Entity

Storm Lake I

Payments to Acquire Business

$ 15.1

Generating Capacity (MW) | MW

108

Assets Acquired [Abstract]

Cash and Cash Equivalents

$ 0.4

Other Current Assets

4.7

Property, Plant and Equipment

47.3

Other Non-Current Assets

^[3]

11.4

Total Assets Acquired

63.8

Liabilities Assumed [Abstract]

Current Liabilities

^[4]

8.2

Power Purchase Agreements - Non-Current Liability

23.5

Non-Current Liabilities

17.0

Total Liabilities Assumed

48.7

Net Identifiable Assets Acquired

15.1

Restricted Cash - Non-Current

$ 0.4

0.4

Goodwill

immaterial

Deductible Goodwill

$ 0.0

0.0

Power Purchase Agreements - Current Liability

$ 7.5

Acquisition-Related Costs

immaterial

[1]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[2]	Power Purchase Agreements acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
[3]	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.
[4]	Current Liabilities included $7.5 million related to the current portion of Power Purchase Agreements.

Goodwill and Intangible Assets - Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Goodwill [Roll Forward]
Beginning Balance	$ 2.9
Acquired Goodwill	127.7
Ending Balance	130.6
ALLETE Clean Energy [Member]
Goodwill [Roll Forward]
Beginning Balance	2.9
Acquired Goodwill	0.4
Ending Balance	3.3
U.S. Water Services [Member]
Goodwill [Roll Forward]
Beginning Balance	0.0
Acquired Goodwill	127.3
Ending Balance	$ 127.3

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

$ 1.9

Additions

^[1]

70.4

Amortization

(4.0)

Other

^[2]

(0.3)

Ending Balance

68.0

Intangible Assets [Abstract]

Total Intangible Assets

84.6

$ 1.9

Total Intangible Assets, Additions

^[1]

87.0

Total Intangible Assets, Amortization

(4.0)

Total Intangible Assets, Other

^[2]

(0.3)

Accumulated Amortization

4.1

$ 0.1

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

5.1

5.0

4.7

4.4

4.2

$ 44.6

Intangible Assets [Abstract]

Useful Life (Years)

3 years

Maximum [Member]

Intangible Assets [Abstract]

Useful Life (Years)

22 years

Weighted Average [Member]

Intangible Assets [Abstract]

Useful Life (Years)

21 years

Trademarks and Trade Names [Member]

Indefinite-Lived Intangible Assets [Roll Forward]

Beginning Balance

$ 0.0

Additions

^[1]

16.6

Other

^[2]

0.0

Ending Balance

16.6

Customer Relationships [Member]

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

0.0

Additions

^[1]

64.0

Amortization

(3.2)

Other

^[2]

0.0

Ending Balance

60.8

Intangible Assets [Abstract]

Total Intangible Assets, Amortization

$ (3.2)

Useful Life (Years)

22 years

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

Beginning Balance

^[3]

$ 1.9

Additions

^[1],[3]

6.4

Amortization

^[3]

(0.8)

Other

^[2],[3]

(0.3)

Ending Balance

^[3]

7.2

Intangible Assets [Abstract]

Total Intangible Assets, Amortization

^[3]

$ (0.8)

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

Intangible Assets [Abstract]

Useful Life (Years)

3 years

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

Intangible Assets [Abstract]

Useful Life (Years)

13 years

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

Intangible Assets [Abstract]

Useful Life (Years)

9 years

[1]	Additions are primarily the result of the U.S. Water Services acquisition. (See Note 7. Acquisitions.)
[2]	Armenia Mountain was acquired on July 1, 2015, at which time the purchase option intangible asset was reclassified as a component of the acquisition consideration.
[3]	Developed Technology and Other includes patents, non-compete agreements, and land easements.

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Investments [Abstract]

ALLETE Properties

$ 50.1

^[1]

$ 88.2

Available-for-sale Securities

18.5

^[2]

18.9

$ 17.7

Cash Equivalents

2.0

2.9

Other

4.0

4.4

Total Other Investments

74.6

114.4

Impairment of Real Estate

36.3

$ 0.0

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

One Year or Less

0.0

One Year to Less Than Three Years

1.0

Three Years to Less Than Five Years

3.2

Five or More Years

$ 6.7

[1]	In 2015, ALLETE Properties recorded a $36.3 million non-cash impairment charge related to its real estate assets. (See Note 1. Operations and Significant Accounting Policies.)
[2]	As of December 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was none, in one year to less than three years was $1.0 million, in three years to less than five years was $3.2 million, and in five or more years was $6.7 million.

Investments - Available-for-sale Securities (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Available-for-sale Securities [Abstract]

Cost

$ 20.0

$ 19.6

$ 18.3

Gross Unrealized Gain

0.0

0.2

0.0

Gross Unrealized Loss

1.5

0.9

0.6

Fair Value

18.5

^[1]

18.9

17.7

Net Proceeds

1.7

3.6

16.1

Gross Realized Gain

0.1

0.2

2.2

Gross Realized Loss

$ 0.0

[1]	As of December 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was none, in one year to less than three years was $1.0 million, in three years to less than five years was $3.2 million, and in five or more years was $6.7 million.

- Definition

Investments in debt and equity securities which are categorized neither as held-to-maturity nor trading and which are intended to be sold or mature more than one year from the balance sheet date or operating cycle, if longer. Such securities are reported at fair value; unrealized gains (losses) related to Available-for-sale Securities are excluded from earnings and reported in a separate component of shareholders' equity (other comprehensive income), unless the Available-for-sale security is designated as a hedge or is determined to have had an other than temporary decline in fair value below its amortized cost basis. All or a portion of the unrealized holding gain (loss) of an Available-for-sale security that is designated as being hedged in a fair value hedge is recognized in earnings during the period of the hedge, as are other than temporary declines in fair value below the cost basis for investments in equity securities and debt securities that an entity intends to sell or it is more likely than not that it will be required to sell before the recovery of its amortized cost basis. Other than temporary declines in fair value below the cost basis for debt securities categorized as Available-for-sale that an entity does not intend to sell and for which it is not more likely than not that the entity will be required to sell before the recovery of its amortized cost basis are bifurcated into credit losses and losses related to all other factors. Other than temporary declines in fair value below cost basis related to credit losses are recognized in earnings, and losses related to all other factors are recognized in other comprehensive income.

+ References + Details

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Investments [Abstract]

Cash Equivalents

$ 2.0

$ 2.9

Liabilities [Abstract]

U.S. Water Services Contingent Consideration

^[1]

36.6

0.0

Recurring Fair Value Measures [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

7.6

^[2]

8.1

^[3]

Available-for-sale - Corporate Debt Securities

10.9

^[2]

10.8

^[3]

Cash Equivalents

2.0

^[2]

2.9

^[3]

Total Fair Value of Assets

20.5

21.8

Liabilities [Abstract]

Deferred Compensation

16.1

^[4]

16.2

^[5]

Derivatives – Interest Rate Swap

^[6]

0.3

U.S. Water Services Contingent Consideration

^[4]

36.6

Total Fair Value of Liabilities

52.7

16.5

Total Net Fair Value of Assets (Liabilities)

(32.2)

5.3

Activity in Level 3 [Roll Forward]

Fair Value Hierarchy Transfers, All Levels

0.0

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

Investments [Abstract]

Available-for-sale - Equity Securities

7.6

^[2]

8.1

^[3]

Available-for-sale - Corporate Debt Securities

0.0

^[2]

0.0

^[3]

Cash Equivalents

2.0

^[2]

2.9

^[3]

Total Fair Value of Assets

9.6

11.0

Liabilities [Abstract]

Deferred Compensation

0.0

^[4]

0.0

^[5]

Derivatives – Interest Rate Swap

^[6]

0.0

U.S. Water Services Contingent Consideration

^[4]

0.0

Total Fair Value of Liabilities

0.0

Total Net Fair Value of Assets (Liabilities)

9.6

11.0

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

Investments [Abstract]

Available-for-sale - Equity Securities

0.0

^[2]

0.0

^[3]

Available-for-sale - Corporate Debt Securities

10.9

^[2]

10.8

^[3]

Cash Equivalents

0.0

^[2]

0.0

^[3]

Total Fair Value of Assets

10.9

10.8

Liabilities [Abstract]

Deferred Compensation

16.1

^[4]

16.2

^[5]

Derivatives – Interest Rate Swap

^[6]

0.3

U.S. Water Services Contingent Consideration

^[4]

0.0

Total Fair Value of Liabilities

16.1

16.5

Total Net Fair Value of Assets (Liabilities)

(5.2)

(5.7)

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

Investments [Abstract]

Available-for-sale - Equity Securities

0.0

^[2]

0.0

^[3]

Available-for-sale - Corporate Debt Securities

0.0

^[2]

0.0

^[3]

Cash Equivalents

0.0

^[2]

0.0

^[3]

Total Fair Value of Assets

0.0

Liabilities [Abstract]

Deferred Compensation

0.0

^[4]

0.0

^[5]

Derivatives – Interest Rate Swap

^[6]

0.0

U.S. Water Services Contingent Consideration

^[4]

36.6

Total Fair Value of Liabilities

36.6

0.0

Total Net Fair Value of Assets (Liabilities)

(36.6)

0.0

Activity in Level 3 [Roll Forward]

Balance as of December 31, 2014

0.0

Activity in Level 3

0.0

Balance as of December 31, 2015

36.6

$ 0.0

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

Activity in Level 3 [Roll Forward]

Activity in Level 3

35.7

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

Activity in Level 3 [Roll Forward]

Activity in Level 3

^[7]

2.4

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

Activity in Level 3 [Roll Forward]

Activity in Level 3

$ (1.5)

[1]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 7. Acquisitions and Note 10. 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 Current Liabilities - Other on the Consolidated Balance Sheet.
[7]	Included in Interest Expense on the Consolidated Statement of Income.

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,605.0	$ 1,373.5
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Current Portion - Fair Value	$ 1,676.0	$ 1,484.5

Fair Value - Nonrecurring Fair Value Measures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Nonrecurring Fair Value Measured [Line Items]
Equity Method Investment, Carrying Amount	$ 124.5	$ 121.1
Goodwill, Carrying Amount	130.6	2.9
Intangible Assets, Carrying Amount	84.6	1.9
Remaining Net Book Value	3,669.1	3,284.8
Taconite Harbor [Member]
Nonrecurring Fair Value Measured [Line Items]
Remaining Net Book Value	100.0
Nonrecurring Fair Value Measurements [Member]
Nonrecurring Fair Value Measured [Line Items]
Equity Method Investment, Impairment		0.0
Goodwill, Carrying Amount	130.6	2.9
Goodwill, Impairment	0.0
Intangible Assets, Carrying Amount	84.6	1.9
Intangible Assets, Impairment	0.0
Property, Plant and Equipment, Impairment	0.0	0.0
Nonrecurring Fair Value Measurements [Member] \| Taconite Harbor [Member]
Nonrecurring Fair Value Measured [Line Items]
Remaining Net Book Value	$ 100.0
ATC [Member]
Nonrecurring Fair Value Measured [Line Items]
Ownership Percentage	8.00%
Equity Method Investment, Carrying Amount	$ 124.5	121.1	$ 114.6
ATC [Member] \| Nonrecurring Fair Value Measurements [Member]
Nonrecurring Fair Value Measured [Line Items]
Ownership Percentage	8.00%
Equity Method Investment, Carrying Amount	$ 124.5	$ 121.1
Equity Method Investment, Impairment	$ 0.0

Short-Term and Long-Term Debt - Short-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Short-term Debt	$ 37.9	$ 104.4
Bank Lines of Credit [Member]
Lines of Credit [Line Items]
Maximum Borrowing Capacity	408.4	408.4
Pledged for Standby Letters of Credit	12.4	47.5
Draws	$ 1.6	$ 3.7

- Definition

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

+ References + Details

Short-Term and Long-Term Debt - Long-Term Debt (Details) $ in Millions	Nov. 05, 2015 USD ($)	Sep. 24, 2015 USD ($)	Aug. 25, 2015 USD ($)	Dec. 31, 2015 USD ($)	Jul. 01, 2015 USD ($)	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Long-Term Debt				$ 1,568.7		$ 1,272.8
Required Indebtedness to Total Capitalization Ratio				0.65
Proceeds from Issuance of First Mortgage Bond		$ 100.0
Long-term Debt Maturities [Abstract]
Long-Term Debt, Maturing in 2016				$ 36.3
Long-Term Debt, Maturing in 2017				193.6
Long-Term Debt, Maturing in 2018				64.1
Long-Term Debt, Maturing in 2019				56.5
Long-Term Debt, Maturing in 2020				103.0
Long-Term Debt, Maturing Thereafter				$ 1,151.5
Armenia Mountain Senior Secured Notes 3.26% Due 2024 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Secured Notes	$ 84.5
Interest Rate	3.26%
ALLETE Term Loan Variable Rate Due 2017 [Member]
Debt Instrument [Line Items]
Principal Amount			$ 125.0
Description of Variable Rate Basis			LIBOR
Basis Spread on Variable Rate			0.625%
Debt Refinanced			$ 75.0
Required Indebtedness to Total Capitalization Ratio			0.65
Cross-Default Amount			$ 35.0
ALLETE First Mortgage Bonds 2.80% Due September 2020 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		$ 40.0
Interest Rate		2.80%
ALLETE First Mortgage Bonds 3.86% Due September 2030 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		$ 60.0
Interest Rate		3.86%
Armenia Mountain [Member]
Debt Instrument [Line Items]
Long-Term Debt					$ 60.9
Long-Term Debt Due Within One Year					$ 5.9

Short-Term and Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total Long-Term Debt	$ 1,605.0	$ 1,373.5
Less: Due Within One Year	36.3	100.7
Net Long-Term Debt	1,568.7	1,272.8
First Mortgage Bonds - 7.70% Series Due 2016 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	20.0	20.0
First Mortgage Bonds - 1.83% Series Due 2018 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0
First Mortgage Bonds - 8.17% Series Due 2019 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	42.0	42.0
First Mortgage Bonds - 5.28% Series Due 2020 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	35.0	35.0
First Mortgage Bonds - 2.80% Series Due 2020 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	40.0	0.0
First Mortgage Bonds - 4.85% Series Due 2021 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0
First Mortgage Bonds - 3.02% Series Due 2021 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	60.0	60.0
First Mortgage Bonds - 3.40% Series Due 2022 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	75.0	75.0
First Mortgage Bonds - 6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	75.0	75.0
First Mortgage Bonds - 3.69% Series Due 2024 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	60.0	60.0
First Mortgage Bonds - 4.90% Series Due 2025 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0
First Mortgage Bonds - 5.10% Series Due 2025 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0
First Mortgage Bonds - 3.20% Series Due 2026 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	75.0	75.0
First Mortgage Bonds - 5.99% Series Due 2027 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	60.0	60.0
First Mortgage Bonds - 3.30% Series Due 2028 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	40.0	40.0
First Mortgage Bonds - 3.74% Series Due 2029 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0
First Mortgage Bonds - 3.86% Series Due 2030 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	60.0	0.0
First Mortgage Bonds - 5.69% Series Due 2036 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0
First Mortgage Bonds - 6.00% Series Due 2040 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	35.0	35.0
First Mortgage Bonds - 5.82% Series Due 2040 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	45.0	45.0
First Mortgage Bonds - 4.08% Series Due 2042 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	85.0	85.0
First Mortgage Bonds - 4.21% Series Due 2043 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	60.0	60.0
First Mortgage Bonds - 4.95% Series Due 2044 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	40.0	40.0
First Mortgage Bonds - 5.05% Series Due 2044 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	40.0	40.0
First Mortgage Bonds - 4.39% Series Due 2044 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0
Unsecured Term Loan Variable Rate Due 2015 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	0.0	75.0
Unsecured Term Loan Variable Rate Due 2017 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	125.0	0.0
Senior Unsecured Notes 5.99% Due 2017 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	13.5	24.6
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	27.8	27.8
Armenia Mountain Senior Secured Notes 3.26% Due 2024 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	83.3	0.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0
Other Long-Term Debt, 0.08% – 7.45% Due 2016 – 2037 [Member]
Debt Instrument [Line Items]
Total Long-Term Debt	$ 68.4	$ 59.1

Short-Term and Long-Term Debt - Financial Covenants (Details)	12 Months Ended
	Dec. 31, 2015
Financial Covenants [Abstract]
Required Indebtedness to Total Capitalization Ratio	0.65
Actual Indebtedness to Total Capitalization Ratio	0.47
Compliance with Financial Covenants	ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) MWh Years MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Square Butte PPA (expires 2026) [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Output Entitlement	50.00%
Square Butte [Member] \| Square Butte PPA (expires 2026) [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Debt Outstanding \| $	$ 376.4
PPA Counterparty Annual Debt Service \| $	45.0
Cost of Purchased Power \| $	77.8	$ 70.1	$ 71.1
Pro Rata Share of PPA Counterparty Interest Expense \| $	$ 10.1	$ 10.5	$ 10.5
Square Butte [Member] \| Square Butte PPA (expires 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 2026) [Member] \| Minnkota Sales Agreement [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Output Entitlement	28.00%	23.00%
Minnkota Power [Member] \| Minnkota Power PPA (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
NextEra Energy, Inc. [Member]
Power Purchase Agreements [Line Items]
Number of PPAs	2
NextEra Energy, Inc. [Member] \| Oliver Wind I PPA (expires 2031) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Fixed Capacity Charges \| $	$ 0.0
NextEra Energy, Inc. [Member] \| Oliver Wind II PPA (expires 2032) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Fixed Capacity Charges \| $	$ 0.0
Manitoba Hydro [Member]
Power Purchase Agreements [Line Items]
Number of PPAs	5
Manitoba Hydro [Member] \| Manitoba Hydro PPA (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	1,000,000
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Term of Contract (Years) \| Years	15
Manitoba Hydro [Member] \| Manitoba Hydro PPA (expires 2040) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	133
Term of Contract (Years) \| Years	20
Manitoba Hydro [Member] \| Manitoba Hydro PPA Beginning June 2017 (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 Only 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 Only PPA Beginning June 2017 (expires May 2020) [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 Power Sales Agreement (expires April 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	100
Term of Contract (Years) \| Years	10
Basin [Member] \| Basin Power Sales Agreement (expires 2018) [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	100
Term of Contract (Years) \| Years	2

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) - Coal Supply and Transportation Agreements [Member] $ in Millions	Dec. 31, 2015 USD ($)
Coal, Rail and Shipping Contracts [Line Items]
Minimum Annual Payment Obligation in 2016	$ 40.7
Minimum Annual Payment Obligation in 2017	27.6
Minimum Annual Payment Obligation in 2018	28.3
Minimum Annual Payment Obligation in 2019	$ 1.8

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leasing Agreements [Line Items]
Minimum Lease Payments in 2016	$ 14.0
Minimum Lease Payments in 2017	12.6
Minimum Lease Payments in 2018	11.1
Minimum Lease Payments in 2019	9.9
Minimum Lease Payments in 2020	6.9
Minimum Lease Payments Thereafter	23.2
Total Lease Expense	17.3	$ 14.8	$ 13.8
BNI Energy Dragline [Member]
Leasing Agreements [Line Items]
Minimum Lease Payments in 2016	2.8
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 Thereafter	19.6
Termination Fee	$ 3.0

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	Dec. 31, 2015 USD ($) Miles kV
CapX2020 [Member]
Transmission [Line Items]
Number of Projects	3
Total Project Costs	$ 100
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	$ 560
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Total Project Cost	$ 710
Completed Project - Prior Years [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of Projects	2

Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) MW
Boswell Unit 4 [Member]
Environmental Matters [Line Items]
Total Project Costs	$ 220
Minimum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	80
Maximum [Member] \| Clean Water Act - Aquatic Organisms [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	15
Maximum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Costs of Compliance	$ 100
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Additional Wind Energy Generating Capacity (MW) \| MW	200
NOV Consent Decree [Member] \| Minimum [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures	$ 20
NOV Consent Decree [Member] \| Maximum [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures	$ 40

Commitments, Guarantees and Contingencies - Other Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) Years	Dec. 31, 2014
U.S. Water Services [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 0.8
BNI Energy Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	47.5
BNI Energy Reclamation Liability [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.6
BNI Energy Reclamation Liability [Member] \| Surety Bonds [Member]
Guarantor Obligations [Line Items]
Collateral	49.9
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	6.3
ALLETE Properties Development and Maintenance Obligations [Member] \| Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	10.3
Town Center Community Development District Capital Improvement Bonds [Member]
Guarantor Obligations [Line Items]
Bonds	$ 26.4
Bond Interest Rate	6.00%
Bond Term (Years) \| Years	31
Ownership Percentage of Benefited Property	72.00%	72.00%
Annual Assessment	$ 1.4
Palm Coast Park Community Development District Special Assessment Bonds[Member]
Guarantor Obligations [Line Items]
Bonds	$ 31.8
Bond Interest Rate	5.70%
Bond Term (Years) \| Years	31
Ownership Percentage of Benefited Property	89.00%	93.00%
Annual Assessment	$ 2.1

Common Stock and Earnings Per Share - Summary of Common Stock (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of Common Stock [Line Items]
Balance, Shares	49,100	45,900
Contributions to Pension, Equity	$ 0.0	$ 19.5	$ 0.0
Common Stock [Member]
Summary of Common Stock [Line Items]
Balance, Shares	49,075	45,929	41,401	39,377
Balance, Equity	$ 1,271.4	$ 1,107.6	$ 885.2	$ 784.7
Employee Stock Purchase Program, Shares	18	18	16
Employee Stock Purchase Program, Equity	$ 0.9	$ 0.8	$ 0.7
Invest Direct, Shares	383	378	395
Invest Direct, Equity	$ 19.0	$ 18.9	$ 18.5
Options and Stock Awards, Shares	43	78	301
Options and Stock Awards, Equity	$ 8.6	$ 8.0	$ 17.9
Equity Issuance Program, Shares	1,289	1,851	1,312
Equity Issuance Program, Equity	$ 69.9	$ 90.0	$ 63.4
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	396	0
Contributions to Pension, Equity		$ 19.5
Equity Issuance Program Shares Authorized	13,600
Equity Issuance Program Shares Available for Issuance	4,000

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
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
Options 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, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 18.3	$ 60.4	$ 22.5	$ 39.9	$ 32.9	$ 41.6	$ 16.8	$ 33.5	$ 141.1	$ 124.8	$ 104.7
Average Common Shares									48.3	42.9	39.7
Earnings Per Share	$ 0.37	$ 1.24	$ 0.46	$ 0.85	$ 0.73	$ 0.97	$ 0.40	$ 0.81	$ 2.92	$ 2.91	$ 2.64
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE									$ 141.1	$ 124.8	$ 104.7
Average Common Shares									48.4	43.1	39.8
Earnings Per Share	$ 0.37	$ 1.23	$ 0.46	$ 0.85	$ 0.73	$ 0.97	$ 0.40	$ 0.80	$ 2.92	$ 2.90	$ 2.63
Dilutive Securities (Shares)									0.1	0.2	0.1
Common Stock [Member]
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share [Line Items]
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share									0.0	0.0	0.0

Other Income (Details) - USD ($) $ in Millions	12 Months Ended
Other Income (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Income and Expenses [Abstract]
AFUDC–Equity	$ 3.3	$ 7.8	$ 4.6
Gain on Sale of Available-for-sale Securities	0.1	0.2	2.2
Investments and Other Income	1.3	0.6	2.5
Total Other Income	$ 4.7	$ 8.6	$ 9.3

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Current Tax Expense [Abstract]

Federal

^[1]

$ 0.0

$ 1.1

$ 0.0

State

^[1]

0.2

2.9

0.1

Total Current Tax Expense

0.2

4.0

0.1

Deferred Tax Expense [Abstract]

Federal

19.4

25.3

22.9

State

6.5

8.2

6.5

Investment Tax Credit Amortization

(0.8)

Total Deferred Tax Expense

25.1

32.7

28.6

Total Income Tax Expense

$ 25.3

$ 36.7

$ 28.7

[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, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Abstract]
Income Before Non-Controlling Interest and Income Taxes	$ 166.8	$ 162.2	$ 133.4
Statutory Federal Income Tax Rate	35.00%	35.00%	35.00%
Income Taxes Computed at 35 Percent Statutory Federal Rate	$ 58.4	$ 56.8	$ 46.7
Increase (Decrease) in Tax [Abstract]
State Income Taxes – Net of Federal Income Tax Benefit	4.4	7.2	4.3
Regulatory Differences for Utility Plant	(0.6)	(3.5)	(2.2)
Production Tax Credits	(37.0)	(23.7)	(19.2)
Other	0.1	(0.1)	(0.9)
Income Tax Expense	$ 25.3	$ 36.7	$ 28.7
Effective Tax Rate on Income	15.20%	22.60%	21.50%

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

Dec. 31, 2015

Dec. 31, 2014

Deferred Tax Assets [Abstract]

Employee Benefits and Compensation

$ 105.4

$ 102.2

Property Related

126.6

102.7

NOL Carryforwards

186.4

156.5

Tax Credit Carryforwards

164.8

95.7

Power Purchase Agreements

73.0

51.8

Other

21.8

17.0

Gross Deferred Tax Assets

678.0

525.9

Deferred Tax Asset Valuation Allowance

(31.6)

(22.1)

Total Deferred Tax Assets

646.4

503.8

Deferred Tax Liabilities [Abstract]

Property Related

1,053.0

848.8

Regulatory Asset for Benefit Obligations

89.4

89.9

Unamortized Investment Tax Credits

26.0

10.3

Partnership Basis Differences

47.8

41.9

Other

10.0

16.1

Total Deferred Tax Liabilities

1,226.2

1,007.0

Net Deferred Income Taxes

579.8

503.2

Net Current Deferred Tax Assets

^[1]

0.0

7.5

Net Long-Term Deferred Tax Liabilities

$ 579.8

$ 510.7

[1]	For discussion of classification of deferred income taxes see Note 1. Operations and Significant Accounting Policies - New Accounting Standards - Balance Sheet Classification of Deferred Taxes.

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

Dec. 31, 2015

Dec. 31, 2014

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforwards

^[1]

$ 493.0

$ 413.7

Tax Credit Carryforwards

113.6

59.3

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]

228.6

184.7

Tax Credit Carryforwards

^[2]

20.0

14.7

Tax Credit Carryforwards, Valuation Allowance

$ 31.2

$ 21.7

[1]	Pretax amounts
[2]	Net of a $31.2 million valuation allowance as of December 31, 2015 ($21.7 million as of December 31, 2014).

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 2.0	$ 1.2	$ 2.7
Additions for Tax Positions Related to the Current Year	0.5	0.0	0.1
Additions for Tax Positions Related to Prior Years	0.7	1.0	1.3
Reduction for Tax Positions Related to Prior Years	(0.7)	0.0	0.0
Reductions for Settlements	0.0	0.0	(2.9)
Lapse of Statute	(0.1)	(0.2)	0.0
Balance as of December 31	2.4	2.0	1.2
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.5
Unrecognized Tax Benefits, Accrued Interest	$ 0.0	$ 0.0	$ 0.5
Unrecognized Tax Benefits, Interest Expense	immaterial	immaterial	immaterial
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, 2015

Dec. 31, 2014

Dec. 31, 2013

Accumulated Other Comprehensive Loss [Roll Forward]

Beginning Balance Accumulated Other Comprehensive Loss

$ (21.1)

$ (17.1)

$ (22.0)

Other Comprehensive Income (Loss) Before Reclassifications

(4.6)

(5.3)

4.6

Amounts Reclassified from Accumulated Other Comprehensive Loss

1.2

1.3

0.3

Net Other Comprehensive Income (Loss)

(3.4)

(4.0)

4.9

Ending Balance Accumulated Other Comprehensive Loss

(24.5)

(21.1)

(17.1)

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

Accumulated Other Comprehensive Loss [Roll Forward]

Beginning Balance Accumulated Other Comprehensive Loss

(0.3)

(0.1)

Other Comprehensive Income (Loss) Before Reclassifications

(0.4)

(0.3)

1.3

Amounts Reclassified from Accumulated Other Comprehensive Loss

(0.1)

0.1

(1.3)

Net Other Comprehensive Income (Loss)

(0.5)

(0.2)

0.0

Ending Balance Accumulated Other Comprehensive Loss

(0.8)

(0.3)

(0.1)

Defined Benefit Pension, Other Postretirement Items [Member]

Accumulated Other Comprehensive Loss [Roll Forward]

Beginning Balance Accumulated Other Comprehensive Loss

^[1]

(20.7)

(16.7)

(21.5)

Other Comprehensive Income (Loss) Before Reclassifications

^[1]

(4.3)

(5.2)

3.2

Amounts Reclassified from Accumulated Other Comprehensive Loss

^[1]

1.3

1.2

1.6

Net Other Comprehensive Income (Loss)

^[1]

(3.0)

(4.0)

4.8

Ending Balance Accumulated Other Comprehensive Loss

^[1]

(23.7)

(20.7)

(16.7)

Gains (Loss) on Cash Flow Hedge [Member]

Accumulated Other Comprehensive Loss [Roll Forward]

Beginning Balance Accumulated Other Comprehensive Loss

(0.1)

(0.3)

(0.4)

Other Comprehensive Income (Loss) Before Reclassifications

0.1

0.2

0.1

Amounts Reclassified from Accumulated Other Comprehensive Loss

0.0

Net Other Comprehensive Income (Loss)

0.1

0.2

0.1

Ending Balance Accumulated Other Comprehensive Loss

$ 0.0

$ (0.1)

$ (0.3)

[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 17. Pension and Other Postretirement Benefit Plans.)

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Pension and Other Postretirement Benefit Plans - Contributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Contributions	$ 0.0	$ 0.0	$ 10.8
Defined Benefit Plans, Employer Contributions	0.0	19.5	0.0
Defined Contribution RSOP, Employer Contributions	9.0	9.1	8.4
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Contributions	0.0	0.0	0.0
Defined Benefit Plans, Employer Contributions		19.5
Defined Benefit Plans, Expected Employer Contributions in 2016	2.0
Postretirement Health and Life [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Expected Employer Contributions in 2016	0.0
VEBA [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Contributions	0.0	0.0	10.8
Irrevocable Grantor Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Contributions	$ 0.0	$ 0.0	$ 2.0

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Change in Plan Assets [Roll Forward]

Non-Current Liabilities

$ (206.8)

$ (190.9)

Other Investments

74.6

114.4

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Accumulated Benefit Obligation

665.0

661.4

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

714.5

622.8

Service Cost

10.1

8.3

$ 9.9

Interest Cost

29.9

29.8

26.0

Actuarial (Gain) Loss

(31.2)

72.6

Benefits Paid

(40.2)

(36.9)

Participant Contributions

26.7

17.9

Obligation, End of Year

709.8

714.5

622.8

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

544.2

501.6

Actual Return on Plan Assets

(10.8)

41.0

Employer Contribution

^[1]

28.1

38.5

Benefits Paid

(40.2)

(36.9)

Fair Value, End of Year

521.3

544.2

501.6

Funded Status, End of Year

(188.5)

(170.3)

Current Liabilities

(1.3)

(1.2)

Non-Current Liabilities

(187.2)

(169.1)

Postretirement Health and Life [Member]

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

170.9

151.9

Service Cost

4.3

3.4

3.9

Interest Cost

7.2

7.3

6.8

Actuarial (Gain) Loss

(14.4)

18.1

Benefits Paid

(10.7)

(8.9)

Participant Contributions

2.9

2.6

Plan Amendments

0.0

(2.9)

Plan Curtailments

0.0

(0.6)

Obligation, End of Year

160.2

170.9

151.9

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

163.2

157.0

Actual Return on Plan Assets

(3.5)

11.6

Employer Contribution

1.5

1.1

Participant Contributions

2.9

2.6

Benefits Paid

(10.7)

(9.1)

Fair Value, End of Year

153.4

163.2

$ 157.0

Funded Status, End of Year

(6.8)

(7.7)

Non-Current Assets

6.4

6.6

Current Liabilities

(1.0)

(0.9)

Non-Current Liabilities

(12.2)

(13.4)

Irrevocable Grantor Trust [Member]

Change in Plan Assets [Roll Forward]

Other Investments

$ 17.4

$ 17.9

[1]	Includes Participant Contributions noted above.

Pension and Other Postretirement Benefit Plans - Unrecognized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 252.7	$ 250.4
Prior Service Cost (Credit)	0.0	0.2
Total Unrecognized Costs (Credit)	252.7	250.6
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	6.5	6.9
Prior Service Cost (Credit)	(7.6)	(10.6)
Total Unrecognized Costs (Credit)	$ (1.1)	$ (3.7)

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Pension [Member]

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

Service Cost

$ 10.1

$ 8.3

$ 9.9

Interest Cost

29.9

29.8

26.0

Expected Return on Plan Assets

(40.7)

(38.2)

(35.2)

Amortization of Loss

17.9

14.2

21.5

Amortization of Prior Service Cost (Credit)

0.2

0.3

Net Expense (Credit)

17.4

14.4

22.5

Postretirement Health and Life [Member]

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

Service Cost

4.3

3.4

3.9

Interest Cost

7.2

7.3

6.8

Expected Return on Plan Assets

(10.9)

(10.3)

(9.7)

Amortization of Loss

0.4

0.5

1.6

Amortization of Prior Service Cost (Credit)

(3.0)

(2.5)

Effect of Plan Settlement

0.0

(1.6)

^[1]

Net Expense (Credit)

$ (2.0)

$ (1.6)

$ (1.5)

[1]	Result of the termination of a legacy benefit plan.

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, 2015	Dec. 31, 2014
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ 20.2	$ 69.8
Amortization of Prior Service (Cost) Credit	(0.2)	(0.3)
Amortization of Loss	(17.9)	(14.2)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	2.1	55.3
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	0.0	16.4
Prior Service Credit Arising During the Period	0.0	(3.0)
Amortization of Prior Service (Cost) Credit	3.0	2.5
Amortization of Loss	(0.4)	(0.5)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$ 2.6	$ 15.4

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, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 709.8	$ 714.5
Accumulated Benefit Obligation	665.0	661.4
Fair Value of Plan Assets	$ 521.3	$ 544.2

Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2015 USD ($)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2016	$ 39.8
2017	40.6
2018	41.1
2019	41.7
2020	41.8
Years 2021 - 2025	216.2
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2016	8.3
2017	8.6
2018	8.8
2019	9.1
2020	9.3
Years 2021 - 2025	$ 48.0

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, 2015 USD ($)
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ (8.4)
Prior Service Credit	0.0
Total Pension and Postretirement Health and Life Credit	(8.4)
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	0.2
Prior Service Credit	(2.9)
Total Pension and Postretirement Health and Life Credit	$ (2.7)

Pension and Other Postretirement Benefit Plans - Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.72%	4.30%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Discount Rate	4.30%	4.93%	4.10%
Expected Long-Term Return on Plan Assets	8.00%	8.00%	8.25%
Pension [Member] \| Minimum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Rate of Compensation Increase	3.70%	3.70%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	3.70%	3.70%	4.30%
Pension [Member] \| Maximum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Rate of Compensation Increase	4.30%	4.30%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	4.30%	4.30%	4.60%
Postretirement Health and Life [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.73%	4.33%
Health Care Trend Rates [Abstract]
Trend Rate	6.50%	6.75%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2022
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Discount Rate	4.33%	4.96%	4.13%
Postretirement Health and Life [Member] \| Minimum [Member]
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	6.40%	6.40%	6.60%
Postretirement Health and Life [Member] \| Maximum [Member]
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	8.00%	8.00%	8.25%

Pension and Other Postretirement Benefit Plans - Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates (Details) - Postretirement Health and Life [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Effect of One Percent Increase on Total of Postretirement Health and Life Service and Interest Cost	$ 1.9
Effect of One Percent Increase on Postretirement Health and Life Obligation	19.3
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.5)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (15.9)

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Pension [Member]

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

Actual Plan Asset Allocation

100.00%

Employer Stock Included in Equity Securities (Shares)

0.0

Plan Asset Target Allocation

100.00%

Pension [Member] | Equity Securities [Member]

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

Actual Plan Asset Allocation

47.00%

48.00%

Plan Asset Target Allocation

56.00%

Pension [Member] | Debt Securities [Member]

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

Actual Plan Asset Allocation

39.00%

Plan Asset Target Allocation

35.00%

Pension [Member] | Private Equity [Member]

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

Actual Plan Asset Allocation

8.00%

Pension [Member] | Real Estate [Member]

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

Actual Plan Asset Allocation

6.00%

5.00%

Plan Asset Target Allocation

9.00%

Postretirement Health and Life [Member]

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

Actual Plan Asset Allocation

^[1]

100.00%

Plan Asset Target Allocation

^[2]

100.00%

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

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

Actual Plan Asset Allocation

^[1]

57.00%

58.00%

Plan Asset Target Allocation

^[2]

60.00%

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

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

Actual Plan Asset Allocation

^[1]

35.00%

34.00%

Plan Asset Target Allocation

^[2]

37.00%

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

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

Actual Plan Asset Allocation

^[1]

8.00%

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

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

Actual Plan Asset Allocation

^[1]

0.00%

Plan Asset Target Allocation

^[2]

3.00%

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

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures, Activity in Level 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 43.3	$ 46.8
Actual Return on Plan Assets	2.6	1.2
Purchases, Sales, and Settlements – Net	(2.6)	(4.7)
Ending Balance	43.3	43.3
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	28.9	26.5
Actual Return on Plan Assets	2.9	2.8
Purchases, Sales, and Settlements – Net	(2.9)	(0.4)
Ending Balance	28.9	28.9
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	12.9	13.1
Actual Return on Plan Assets	1.2	1.4
Purchases, Sales, and Settlements – Net	(2.1)	(1.6)
Ending Balance	$ 12.0	$ 12.9

Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [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 newly issued common stock. The note was refinanced in 2006 at 6 percent and subsequently matured in December 2015.
ESOP Compensation Expense	$ 9.0	$ 9.1	$ 8.4
ESOP Shares, Allocated	1.8	1.9	2.0
ESOP Shares, Unallocated	0.0	0.3	0.5
ESOP Shares, Total	1.8	2.2	2.5
ESOP Shares, Fair Value of Unallocated Shares	$ 0.0	$ 13.2	$ 24.1

Employee Stock and Incentive Plans - Stock-Based Compensation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2015 shares
Non-Qualified Stock Options [Member]
Stock-based Compensation [Line Items]
Requisite Service Period (Years)	1 year
Vesting Period (Years)	3 years
Exercise Period (Years/Months)	10 years
Non-Qualified Stock Options [Member] \| Qualified Retirement, Death or Disability [Member]
Stock-based Compensation [Line Items]
Exercise Period (Years/Months)	3 years
Non-Qualified Stock Options [Member] \| Voluntary Termination or Involuntary Termination Without Cause [Member]
Stock-based Compensation [Line Items]
Exercise Period (Years/Months)	3 months
Performance Shares [Member]
Stock-based Compensation [Line Items]
Vesting Period (Years)	3 years
Restricted Stock Units [Member]
Stock-based Compensation [Line Items]
Vesting Period (Years)	3 years
Employee Stock Purchase Plan (ESPP) [Member]
Stock-based Compensation [Line Items]
ESPP Discount	5.00%
Executive Long-Term Incentive Compensation Plan [Member]
Stock-based Compensation [Line Items]
Common Stock Reserved	1.1
Shares Available for Issuance	0.9

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 2.6	$ 2.3	$ 2.4
Income Tax Benefit	1.1	1.0	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	1.6	1.7
Unrecognized Compensation Cost	$ 1.9
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	$ 0.7	$ 0.7
Unrecognized Compensation Cost	$ 1.1
Weighted-Average Period for Recognition (Years/Months)	1 year 11 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, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2008

Number of Options [Roll Forward]

Outstanding as of January 1

66,279

108,299

395,678

Granted

^[1]

Exercised

(24,456)

(42,020)

(287,379)

Forfeited

(2,169)

Outstanding as of December 31

39,654

66,279

108,299

Exercisable as of December 31

39,654

66,279

108,299

Weighted-Average Exercise Price [Abstract]

Outstanding as of January 1

$ 44.39

$ 44.10

$ 42.28

Granted

^[1]

0.00

Exercised

44.52

43.65

41.60

Forfeited

42.93

0.00

Outstanding as of December 31

44.39

44.10

Exercisable as of December 31

$ 44.39

$ 43.17

Weighted Average Grant-Date Intrinsic Value

$ 6.18

Cash Received from Non-Qualified Stock Options Exercised

$ 1.1

Total Intrinsic Value of Options Exercised

$ 0.2

$ 0.4

$ 2.2

[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, 2015 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	16,620
Outstanding - Weighted Average Remaining Contractual Life (Years/Months)	2 years 1 month
Outstanding - Weighted Average Exercise Price	$ 39.10
Outstanding - Aggregate Intrinsic Value (Millions) \| $	$ 0.2
Number Exercisable \| shares	16,620
Exercisable - Weighted Average Remaining Contractual Life (Years/Months)	2 years 1 month
Exercisable - Weighted Average Exercise Price	$ 39.10
Exercisable - Aggregate Intrinsic Value (Millions) \| $	$ 0.2
$44.15 [Member]
Range of Exercise Price [Line Items]
Lower Range Limit	$ 44.15
Upper Range Limit	$ 44.15
Options Outstanding and Exercisable [Abstract]
Number Outstanding \| shares	2,306
Outstanding - Weighted Average Remaining Contractual Life (Years/Months)	1 month
Outstanding - Weighted Average Exercise Price	$ 44.15
Outstanding - Aggregate Intrinsic Value (Millions) \| $	$ 0.0
Number Exercisable \| shares	2,306
Exercisable - Weighted Average Remaining Contractual Life (Years/Months)	1 month
Exercisable - Weighted Average Exercise Price	$ 44.15
Exercisable - Aggregate Intrinsic Value (Millions) \| $	$ 0.0
$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	20,728
Outstanding - Weighted Average Remaining Contractual Life (Years/Months)	1 year 1 month
Outstanding - Weighted Average Exercise Price	$ 48.65
Outstanding - Aggregate Intrinsic Value (Millions) \| $	$ 0.1
Number Exercisable \| shares	20,728
Exercisable - Weighted Average Remaining Contractual Life (Years/Months)	1 year 1 month
Exercisable - Weighted Average Exercise Price	$ 48.65
Exercisable - Aggregate Intrinsic Value (Millions) \| $	$ 0.1

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. 22, 2016

Jan. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Performance Shares [Member]

Number of Shares [Rollforward]

As of January 1

119,540

119,635

114,765

107,899

Granted

^[1]

43,583

47,992

45,830

Awarded

(36,515)

(18,605)

Unearned Grant Award

(36,670)

(18,606)

Forfeited

(7,008)

(6,607)

(1,753)

As of December 31

119,540

119,635

114,765

Performance Period (Years)

3 years

Weighted-Average Grant Date Fair Value [Abstract]

As of January 1

$ 52.72

$ 48.26

$ 47.02

$ 40.73

Granted

^[1]

58.95

46.47

52.15

Awarded

0.00

42.01

35.10

Unearned Grant Award

45.41

0.00

35.10

Forfeited

53.49

48.29

47.26

As of December 31

$ 52.72

$ 48.26

$ 47.02

Restricted Stock Units [Member]

Number of Shares [Rollforward]

As of January 1

57,694

53,888

55,982

56,415

Granted

^[2]

26,702

19,645

21,440

Awarded

(19,464)

(18,860)

(20,939)

Forfeited

(3,432)

(2,879)

(934)

As of December 31

57,694

53,888

55,982

Performance Period (Years)

3 years

Weighted-Average Grant Date Fair Value [Abstract]

As of January 1

$ 49.86

$ 44.47

$ 40.85

$ 36.61

Granted

^[2]

54.81

48.44

43.41

Awarded

41.44

37.64

32.03

Forfeited

51.52

45.92

41.02

As of December 31

$ 49.86

$ 44.47

$ 40.85

Subsequent Event [Member] | Performance Shares [Member]

Number of Shares [Rollforward]

Granted

51,586

Awarded

Performance Period (Years)

3 years

Granted, Grant Date Fair Value

$ 2.7

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

Number of Shares [Rollforward]

Granted

17,396

Awarded

(17,608)

Granted, Grant Date Fair Value

$ 0.9

Awarded, Grant Date Fair Value

$ 0.8

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

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating Revenue	$ 380.6	$ 462.5	$ 323.3	$ 320.0	$ 290.7	$ 288.9	$ 260.7	$ 296.5	$ 1,486.4	$ 1,136.8	$ 1,018.4
Operating Income	29.6	85.2	39.5	56.4	51.5	60.8	28.2	48.3	210.7	188.8	154.1
Net Income Attributable to ALLETE	$ 18.3	$ 60.4	$ 22.5	$ 39.9	$ 32.9	$ 41.6	$ 16.8	$ 33.5	$ 141.1	$ 124.8	$ 104.7
Basic Earnings Per Share of Common Stock	$ 0.37	$ 1.24	$ 0.46	$ 0.85	$ 0.73	$ 0.97	$ 0.40	$ 0.81	$ 2.92	$ 2.91	$ 2.64
Diluted Earnings Per Share of Common Stock	$ 0.37	$ 1.23	$ 0.46	$ 0.85	$ 0.73	$ 0.97	$ 0.40	$ 0.80	$ 2.92	$ 2.90	$ 2.63