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Document and Entity Information Document - USD ($)	3 Months Ended
Document and Entity Information Document - USD ($)	Mar. 31, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
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		$ 2,175,249,161
Entity Common Stock, Shares Outstanding	48,751,109
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2015

Consolidated Balance Sheet - USD ($) $ in Millions	Mar. 31, 2015	Dec. 31, 2014
Current Assets [Abstract]
Cash and Cash Equivalents	$ 72.1	$ 145.8
Accounts Receivable (Less Allowance of $1.1 and $1.1)	111.8	103.0
Inventories	102.7	80.5
Prepayments and Other	88.5	82.0
Deferred Income Taxes	14.9	7.5
Total Current Assets	390.0	418.8
Property, Plant and Equipment - Net	3,319.2	3,284.8
Regulatory Assets	358.0	357.3
Investment in ATC	122.3	121.1
Other Investments	114.7	114.4
Goodwill and Intangible Assets – Net	214.3	4.8
Other Non-Current Assets	61.6	59.6
Total Assets	4,580.1	4,360.8
Current Liabilities [Abstract]
Accounts Payable	98.9	134.1
Accrued Taxes	47.4	38.7
Accrued Interest	14.5	18.0
Long-Term Debt Due Within One Year	122.3	100.7
Notes Payable	0.3	3.7
Other	118.6	120.8
Total Current Liabilities	402.0	416.0
Long-Term Debt	1,253.8	1,272.8
Deferred Income Taxes	559.5	510.7
Regulatory Liabilities	101.2	94.2
Defined Benefit Pension and Other Postretirement Benefit Plans	190.4	190.9
Other Non-Current Liabilities	302.3	265.0
Total Liabilities	2,809.2	2,749.6
Commitments, Guarantees and Contingencies (Note 16)
Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 48.8 and 45.9 Shares Outstanding	1,249.7	1,107.6
Unearned ESOP Shares	(5.3)	(7.2)
Accumulated Other Comprehensive Loss	(20.6)	(21.1)
Retained Earnings	545.1	530.1
Total ALLETE Equity	1,768.9	1,609.4
Non-Controlling Interest in Subsidiaries	2.0	1.8
Total Equity	1,770.9	1,611.2
Total Liabilities and Equity	$ 4,580.1	$ 4,360.8

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Mar. 31, 2015	Dec. 31, 2014
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.1	$ 1.1
Common Stock [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	48.8	45.9

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Consolidated Statement of Income [Abstract]
Operating Revenue	$ 320.0	$ 296.5
Operating Expenses [Abstract]
Fuel and Purchased Power	86.0	96.2
Transmission Services	14.9	10.8
Cost of Sales	31.2	23.5
Operating and Maintenance	79.7	74.3
Depreciation and Amortization	39.0	32.2
Taxes Other than Income Taxes	12.8	11.2
Total Operating Expenses	263.6	248.2
Operating Income	56.4	48.3
Other Income (Expense) [Abstract]
Interest Expense	(15.1)	(12.8)
Equity Earnings in ATC	3.9	5.1
Other	1.1	2.0
Total Other Expense	(10.1)	(5.7)
Income Before Non-Controlling Interest and Income Taxes	46.3	42.6
Income Tax Expense	6.2	8.8
Net Income	40.1	33.8
Less: Non-Controlling Interest in Subsidiaries	0.2	0.3
Net Income Attributable to ALLETE	$ 39.9	$ 33.5
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (in shares)	46.9	41.4
Diluted (in shares)	47.1	41.6
Basic Earnings Per Share of Common Stock	$ 0.85	$ 0.81
Diluted Earnings Per Share of Common Stock	0.85	0.80
Dividends Per Share of Common Stock	$ 0.505	$ 0.49

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Comprehensive Income [Abstract]
Net Income	$ 40.1	$ 33.8
Other Comprehensive Income [Abstract]
Unrealized Gain on Securities, Net of Income Taxes of $0.1 and $-	0.1	0.0
Unrealized Gain on Derivatives, Net of Income Taxes of $- and $0.1	0.1	0.0
Defined Benefit Pension and Other Postretirement Benefit Plans, Net of Income Taxes of $0.2 and $0.2	0.3	0.3
Total Other Comprehensive Income	0.5	0.3
Total Comprehensive Income	40.6	34.1
Less: Non-Controlling Interest in Subsidiaries	0.2	0.3
Comprehensive Income Attributable to ALLETE	$ 40.4	$ 33.8

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain on Securities, Tax	$ 0.1	$ 0.0
Unrealized Gain on Derivatives, Tax	0.0	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Tax	$ 0.2	$ 0.2

Consolidated Statement of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Operating Activities [Abstract]
Net Income	$ 40.1	$ 33.8
Allowance for Funds Used During Construction – Equity	(0.9)	(1.8)
Income from Equity Investments, Net of Dividends	(0.8)	(0.8)
Depreciation Expense	38.4	32.2
Amortization of Intangible Assets and Other Assets	0.8	0.3
Amortization of Power Purchase Agreements	(4.9)	(2.3)
Deferred Income Tax Expense	6.1	8.8
Share-Based Compensation Expense	0.6	0.8
ESOP Compensation Expense	2.4	2.2
Defined Benefit Pension and Postretirement Benefit Expense	3.8	3.2
Bad Debt Expense	0.2	0.2
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	7.8	2.9
Inventories	(8.8)	(6.5)
Prepayments and Other	(0.7)	2.2
Accounts Payable	(14.0)	0.1
Other Current Liabilities	(1.7)	1.6
Changes in Regulatory and Other Non-Current Assets	(4.1)	(4.0)
Changes in Regulatory and Other Non-Current Liabilities	7.5	2.0
Cash from Operating Activities	71.8	74.9
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	0.2	0.6
Payments for Purchase of Available-for-sale Securities	(0.4)	(0.7)
Acquisitions of Subsidiaries – Net of Cash Acquired	(166.9)	(23.1)
Investment in ATC	(0.4)	(1.2)
Changes to Other Investments	0.0	30.0
Additions to Property, Plant and Equipment	(88.2)	(216.2)
Construction Costs for Development Project	(0.2)	0.0
Cash in Escrow for Acquisition	0.0	6.0
Cash for Investing Activities	(255.9)	(204.6)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	141.5	24.8
Proceeds from Issuance of Long-Term Debt	0.0	100.0
Changes in Restricted Cash	(0.8)	0.0
Changes in Notes Payable	(3.4)	0.0
Reductions of Long-Term Debt	(2.0)	(19.8)
Acquisition of Non-Controlling Interest	0.0	(6.0)
Debt Issuance Costs	0.0	(0.9)
Dividends on Common Stock	(24.9)	(21.1)
Cash from Financing Activities	110.4	77.0
Change in Cash and Cash Equivalents	(73.7)	(52.7)
Cash and Cash Equivalents at Beginning of Period	145.8	97.3
Cash and Cash Equivalents at End of Period	$ 72.1	$ 44.6

Operations and Significant Accounting Policies

3 Months Ended

Mar. 31, 2015

Operations and Significant Accounting Policies [Abstract]

Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Reclassifications. As a result of recent acquisitions, certain financial statement captions have been added and as a result we have reclassified certain prior-period amounts in our Consolidated Balance Sheet, Consolidated Statement of Income, and Consolidated Statement of Cash Flows 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 $23.5 million from Operating and Maintenance Expenses to Cost of Sales for the three months ended March 31, 2014. Cost of Sales includes purchased gas at SWL&P, expenses incurred to deliver coal at BNI Coal, and the cost of land and other sales at ALLETE Properties. There was no impact to Operating Income, Net Income, or Net Income Attributable to ALLETE as a result of the reclassification. Cost of Sales also includes costs associated with the manufacture and delivery of inventories at U.S. Water Services, our integrated water management company which was acquired February 10, 2015. (See Note 4. 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, $10.8 million of Transmission Services and $11.2 million of Taxes Other than Income Taxes have been reclassified from Operating and Maintenance Expenses for the three months ended March 31, 2014.

Consolidated Statement of Cash Flows. In conformity with the current presentation of the Amortization of Power Purchase Agreements on the Consolidated Statement of Cash Flows, we have reclassified $2.3 million from Changes in Regulatory and Other Non-Current Liabilities to Amortization of Power Purchase Agreements for the three months ended March 31, 2014. There was no impact on cash from (for) Operating Activities, Investing Activities, and Financing Activities as a result of the reclassifications.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventories in our Regulated Operations segment are recorded on an average cost basis. Amounts removed from inventories in our Investments and Other segment are recorded on an average cost, first-in, first-out or specific identification basis.



Inventories	March 31, 2015			December 31, 2014
Millions
Regulated Operations Inventories
Fuel		$38.0			$29.0
Materials and Supplies	34.6			35.2
Total Regulated Operations Inventories	72.6			64.2
Investments and Other Inventories (a)
Materials and Supplies	16.3			16.3
Raw Materials	3.1			—
Work in Progress	1.0			—
Finished Goods	10.2			—
Reserve for Obsolescence	(0.5		)	—
Total Investments and Other Inventories	30.1			16.3
Total Inventories		$102.7			$80.5


(a)	Raw materials, Work in Progress, Finished Goods, and Reserve for Obsolescence presented are attributable to U.S. Water Services which was acquired February 10, 2015.



Prepayments and Other Current Assets	March 31, 2015		December 31, 2014
Millions
Deferred Fuel Adjustment Clause		$15.6		$16.3
Construction Costs for Development Project (a)	48.4		48.2
Restricted Cash (b)	5.6		2.7
Other	18.9		14.8
Total Prepayments and Other Current Assets		$88.5		$82.0


(a)	Construction Costs for Development Project relate to ALLETE Clean Energy’s acquisition in November 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 4. Acquisitions.)


(b)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.

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 U.S. GAAP, goodwill is not amortized. The Company assesses whether there has been an impairment of goodwill annually in the third quarter 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 future 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, patents and non-compete agreements, which are amortized on a straight-line or accelerated basis with estimated useful lives ranging from less than 1 year to 23 years. We review other 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 third 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 future cash flow analysis.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets.

Restricted Cash. Included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $5.3 million as of March 31, 2015 and December 31, 2014, related to ALLETE Clean Energy’s wind energy facilities debt service and other requirements.



Other Current Liabilities	March 31, 2015		December 31, 2014
Millions
Customer Deposits		$20.0		$19.7
Power Purchase Agreements (a)	18.9		19.4
Construction Deposits Received for Development Project (b)	54.3		54.3
Other	25.4		27.4
Total Other Current Liabilities		$118.6		$120.8


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)


(b)	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayments and Other Current Assets table and Note 4. Acquisitions.)



Other Non-Current Liabilities	March 31, 2015		December 31, 2014
Millions
Asset Retirement Obligation		$111.6		$109.2
Power Purchase Agreements (a)	106.3		110.7
Contingent Consideration (b)	35.8		—
Other	48.6		45.1
Total Other Non-Current Liabilities		$302.3		$265.0


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment to acquire the remaining ownership interest in U.S. Water Services. (See Note 4. Acquisitions and Note 7. Fair Value.)

Supplemental Statement of Cash Flows Information.



Three Months Ended March 31,	2015		2014
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$15.3		$12.4
Cash Paid During the Period for Income Taxes		$0.1		$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(32.2)		$(22.6)
Capitalized Asset Retirement Costs	$1.2			$0.6
AFUDC–Equity		$0.9		$1.8
ALLETE Common Stock Contributed to the Pension Plan	—			$19.5
Contingent Consideration		$35.7	—

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 is effective beginning in the first quarter of 2015, and applies prospectively to new disposals and new classifications of disposal groups as held for sale. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

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. Early adoption is not permitted for public companies. On April 1, 2015, the FASB voted to propose a deferral of the effective date of the standard by one year which would make the guidance effective for the Company beginning in the first quarter of 2018. The FASB is expected to issue updated accounting guidance regarding the deferred effective date, subject to a 30-day comment period, in the second quarter of 2015. 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 in the 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. We are evaluating the impact of the adoption of this standard.

Business Segments

3 Months Ended

Mar. 31, 2015

Business Segments [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

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. Investments and Other is comprised primarily of our Energy Infrastructure and Related Services businesses: ALLETE Clean Energy, our business aimed at 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, our integrated water management company which was acquired on February 10, 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and 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. Future acquisitions or growth may impact segment reporting.



	Consolidated			Regulated Operations			Investments and Other
Millions
Three Months Ended March 31, 2015
Operating Revenue		$320.0			$262.8			$57.2
Fuel and Purchased Power	86.0			86.0			—
Transmission Services	14.9			14.9			—
Cost of Sales	31.2			4.5			26.7
Operating and Maintenance	79.7			58.7			21.0
Depreciation and Amortization	39.0			32.1			6.9
Taxes Other than Income Taxes	12.8			11.6			1.2
Operating Income	56.4			55.0			1.4
Interest Expense	(15.1		)	(13.0		)	(2.1		)
Equity Earnings in ATC	3.9			3.9			—
Other Income	1.1			0.9			0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	46.3			46.8			(0.5		)
Income Tax Expense	6.2			5.4			0.8
Net Income (Loss)	40.1			41.4			(1.3		)
Less: Non-Controlling Interest in Subsidiaries	0.2			—			0.2
Net Income (Loss) Attributable to ALLETE		$39.9			$41.4		$(1.5)

As of March 31, 2015
Total Assets		$4,580.1			$3,748.4			$831.7
Property, Plant and Equipment – Net		$3,319.2			$3,025.3			$293.9
Accumulated Depreciation		$1,367.0			$1,286.9			$80.1
Capital Additions		$57.3			$54.9			$2.4

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
Three Months Ended March 31, 2014
Operating Revenue		$296.5			$264.2			$32.3
Fuel and Purchased Power	96.2			96.2			—
Transmission Services	10.8			10.8			—
Cost of Sales	23.5			8.7			14.8
Operating and Maintenance	74.3			60.5			13.8
Depreciation and Amortization	32.2			28.8			3.4
Taxes Other than Income Taxes	11.2			10.2			1.0
Operating Income (Loss)	48.3			49.0			(0.7		)
Interest Expense	(12.8		)	(11.5		)	(1.3		)
Equity Earnings in ATC	5.1			5.1			—
Other Income	2.0			1.8			0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	42.6			44.4			(1.8		)
Income Tax Expense (Benefit)	8.8			10.5			(1.7		)
Net Income (Loss)	33.8			33.9			(0.1		)
Less: Non-Controlling Interest in Subsidiaries	0.3			—			0.3
Net Income (Loss) Attributable to ALLETE		$33.5			$33.9		$(0.4)

As of March 31, 2014
Total Assets		$3,749.2			$3,335.5			$413.7
Property, Plant and Equipment – Net		$2,905.1			$2,671.3			$233.8
Accumulated Depreciation		$1,266.7			$1,202.9			$63.8
Capital Additions		$195.2			$193.5			$1.7

- 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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8595-108599

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-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9031-108599

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

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-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8538-108599

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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

+ Details

Investments

3 Months Ended

Mar. 31, 2015

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At March 31, 2015, our investment portfolio included the 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	March 31, 2015		December 31, 2014
Millions
ALLETE Properties		$88.3		$88.2
Available-for-sale Securities (a)	19.3		18.9
Cash Equivalents	2.8		2.9
Other	4.3		4.4
Total Other Investments		$114.7		$114.4


(a)	As of March 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.4 million, in one year to less than three years was $1.7 million, in three years to less than five years was $3.0 million, and in five or more years was $5.9 million.

NOTE 3. INVESTMENTS (Continued)



ALLETE Properties	March 31, 2015		December 31, 2014
Millions
Land Inventory Beginning Balance		$83.8		$85.4
Cost of Sales	—		(2.2		)
Other	0.1		0.6
Land Inventory Ending Balance	83.9		83.8
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.2		1.2
Other	3.2		3.2
Total Real Estate Assets		$88.3		$88.2

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 fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairments were recorded for the three months ended March 31, 2015 (none for the year ended December 31, 2014).

Long-Term Finance Receivables. As of March 31, 2015, long-term finance receivables were $1.2 million net of an allowance ($1.2 million net of an allowance as of December 31, 2014). Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. As of March 31, 2015, the allowance for doubtful accounts amounted to $0.6 million ($0.6 million as of December 31, 2014).



Available-For-Sale Securities
Millions		Gross Unrealized
	Cost	Gain	Loss	Fair Value
March 31, 2015	$19.8	$0.3	$0.8	$19.3
December 31, 2014	$19.6	$0.2	$0.9	$18.9

Acquisitions

3 Months Ended

Mar. 31, 2015

Acquisition [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 three months ended March 31, 2015 and year ended December 31, 2014.

2015 Acquisition 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 for an 87 percent ownership interest in the company, and an estimated fair value of earnings-based contingent consideration of $35.7 million to be paid in 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 of U.S. Water Services since the acquisition date as the Company has effectively acquired 100 percent of U.S. Water Services. U.S. Water Services, an integrated industrial water management company headquartered in St. Michael, Minnesota, provides integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services helps customers achieve efficient and sustainable use of their energy systems, is a leading provider to the biofuels industry, and has a growing presence in the power generation and midstream oil and gas industries.

NOTE 4. ACQUISITIONS (Continued)

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to customer relationships, developed technologies, trademarks and trade names, and current and deferred income taxes; subsequent adjustments could impact the amount of goodwill recorded. 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
Goodwill (c)	127.1
Intangible Assets (d)	83.0
Other Non-Current Assets	0.2
Total Assets Acquired		$257.3
Liabilities Assumed
Other Current Liabilities		$18.7
Other Non-Current Liabilities	36.3
Total Liabilities Assumed		$55.0
Net Identifiable Assets Acquired		$202.3


(a)	Included in Inventories was $2.7 million of fair value adjustments relating to work in process 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 stand-by letters of credit.


(c)	Goodwill is largely attributable to strategic opportunities for growing U.S. Water Services and the benefits of the existing workforce. Goodwill of $3.2 million is deductible for tax purposes.


(d)	Intangible Assets include customer relationships, patents, non-compete agreements and trademarks and trade names. (See Note 5. Goodwill and Intangible Assets.)

ALLETE incurred a $3.0 million after-tax expense of acquisition-related costs during the three months ended March 31, 2015, which were expensed when incurred and were recorded in Operating and Maintenance on the Consolidated Statement of Income.

Chanarambie/Viking. On April 15, 2015, ALLETE Clean Energy acquired wind energy facilities in southern Minnesota (Chanarambie/Viking) from EDF Energy Holdings Limited for $47.5 million, subject to a working capital adjustment. We are currently in the process of accounting for the acquisition, therefore, certain disclosures, including the allocation of the purchase price, will be included in the Form 10-Q for the period ending June 30, 2015.

The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 (12 MW) and 2023 (85.5 MW).

Armenia Mountain. On April 30, 2015, ALLETE Clean Energy signed purchase agreements to acquire 100 percent of a wind energy facility located near Troy, Pennsylvania (Armenia Mountain) from The AES Corporation (AES) and a non-controlling interest from a minority shareholder for $108.0 million, plus the assumption of existing debt. The agreement with AES is subject to a purchase price adjustment. The acquisition is expected to close in July 2015.

The facility has 100.5 MW of generating capability, began commercial operations in 2009, and has PPAs in place for the entire output, which expire in 2025.

NOTE 4. ACQUISITIONS (Continued)

2014 Acquisition 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.



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
Other 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 in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.


(c)	The purchase price accounting valued the non-controlling interest relating to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.

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.

Montana-Dakota Utilities. In November 2014, ALLETE Clean Energy acquired a business for $27.0 million to develop a wind facility near Hettinger, North Dakota. ALLETE Clean Energy is developing and constructing a 107 MW wind facility consisting of 43 turbines, which will be sold to Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approval from the NDPSC. If regulatory approval is not obtained for the sale of the wind facility, ALLETE Clean Energy would then own and operate the facility and sell the entire output to Montana-Dakota Utilities Co. under a long-term PPA.

NOTE 4. ACQUISITIONS (Continued)

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and 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 approximately $3.6 million and construction in process of approximately $23.4 million. There were no liabilities assumed and no recognition of goodwill.

As of March 31, 2015, $48.4 million of construction costs incurred (including the construction costs acquired) and $54.3 million of construction deposits received from Montana-Dakota Utilities Co. have been classified on the Consolidated Balance Sheet as Prepayments and Other Current Assets and Other Current Liabilities, respectively ($48.2 million and $54.3 million of costs incurred and deposits received as of December 31, 2014, respectively). ALLETE expects revenue to be recognized under the percentage of completion method of accounting as progress toward completion of the project is achieved. Until it becomes probable that regulatory approval from the NDPSC for the sale of the facility will be obtained, we expect no impact from the project on the Consolidated Statement of Income. Costs to construct the wind facility and deposits received from Montana-Dakota Utilities Co. are reported as Construction Costs for Development Project in investing activities and Construction Deposits Received for Development Project in financing activities on the Consolidated Statement of Cash Flows, respectively. On April 15, 2015, we received an additional construction deposit from Montana-Dakota Utilities Co. of approximately $50 million.

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 generation facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

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. In connection with finalizing purchase price accounting, the Company recorded minor adjustments during the first quarter of 2015 to certain assets and liabilities, which are reflected in the table below. The result of these adjustments had no impact on the results of operations for the period ended March 31, 2015. Fair value measurements were valued primarily using the discounted cash flow method.



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
Other Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
Other 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)	Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.

- 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

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+ Details

Goodwill and Intangible Assets

3 Months Ended

Mar. 31, 2015

Goodwill and Intangible Assets [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The following table summarizes changes to goodwill by business segment for the three months ended March 31, 2015:




	Investments and Other
Millions
Balance as of December 31, 2014		$2.9
Acquired Goodwill	127.1
Balance as of March 31, 2015		$130.0

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



	December 31, 2014		Additions as a Result of Acquisitions		Amortization	March 31, 2015
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	—			$60.1	$0.5		$59.6
Developed Technology and Other (a)		$1.9	6.3		0.1	8.1
Total Definite-Lived Intangible Assets	1.9		66.4		0.6	67.7
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	—		16.6		n/a	16.6
Total Intangible Assets		$1.9		$83.0	$0.6		$84.3


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

Customer relationships have a useful life of approximately 23 years and developed technology and other have useful lives ranging from less than 1 year to approximately 14 years (weighted average of approximately 9 years). The weighted average useful life of all definite-lived intangible assets as of March 31, 2015 is approximately 21 years.

Amortization expense of intangible assets for the three months ended March 31, 2015 was $0.6 million.

The estimated amortization expense for definite-lived intangible assets for the remainder of 2015 is $3.6 million. Estimated annual amortization expense for definite-lived intangible assets is $4.3 million in 2016, $4.2 million in 2017, $4.1 million in 2018, $4.0 million in 2019, $3.9 million in 2020 and $43.6 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

Derivatives	3 Months Ended
Derivatives	Mar. 31, 2015
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES We have one variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million term loan which represents approximately 5 percent of the Company’s outstanding long-term debt, including long-term debt due within one year, as of March 31, 2015. (See Note 10. Short-Term and Long-Term Debt.) The Swap has an effective date of August 26, 2014, and matures on August 25, 2015. The Swap involves the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreement at 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swap are expected to be highly effective. If it is determined that the Swap ceases to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessment of hedge effectiveness resulted in no ineffectiveness recorded for the three months ended March 31, 2015. As of March 31, 2015, the fair value of the Swap was a $0.2 million liability ($0.3 million liability as of December 31, 2014) which was included in Other Current Liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swap were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swap are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income related to the Swap will be recorded in earnings when the hedged transaction occurs or when it is probable it will not occur. Gains or losses on the interest rate hedging transaction are reflected as a component of Interest Expense on the Consolidated Statement of Income.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41638-113959

Reference 19: 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.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value

3 Months Ended

Mar. 31, 2015

Fair Value [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). Descriptions of the three levels of the fair value hierarchy are discussed in Note 10. Fair Value to the Consolidated Financial Statements in our 2014 Form 10-K.

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 March 31, 2015, and December 31, 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 tables below.

NOTE 7. FAIR VALUE (Continued)



	Fair Value as of March 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.3	—		—			$8.3
Available-for-sale – Corporate Debt Securities	—			$11.0	—		11.0
Cash Equivalents	2.8		—		—		2.8
Total Fair Value of Assets		$11.1		$11.0	—			$22.1

Liabilities:
Deferred Compensation (b)	—			$15.4	—			$15.4
Derivatives – Interest Rate Swap (c)	—		0.2		—		0.2
U.S. Water Services Contingent Consideration (b)	—		—			$35.8	35.8
Total Fair Value of Liabilities	—			$15.6		$35.8		$51.4
Total Net Fair Value of Assets (Liabilities)		$11.1	$(4.6)		$(35.8)		$(29.3)


(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.



	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 March 31, 2015. The acquisition contingent consideration is recorded at the acquisition date at the estimated fair value of the acquisition contingent consideration. 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 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 result in different fair value measurements and expense (or income) in the current or future periods. The acquisition contingent consideration was measured at $35.8 million as of March 31, 2015.

NOTE 7. FAIR VALUE (Continued)



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance at December 31, 2014	—
Recognition of U.S. Water Services Contingent Consideration	$35.7
Accretion Expense	0.1
Balance at March 31, 2015		$35.8

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.

For the three months ended March 31, 2015 and the year ended December 31, 2014, there were no transfers in or out of Levels 1, 2 or 3.

Fair Value of Financial Instruments. With the exception of the item listed in the table below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed 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
March 31, 2015	$1,376.1	$1,525.4
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, Rainy River Energy, 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 9. Investment in ATC.) The aggregate carrying amount of the investment was $122.3 million as of March 31, 2015 and $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 three months ended March 31, 2015 and the year ended December 31, 2014, there were no indicators of impairment.

Goodwill. The Company assesses the impairment of goodwill annually in the third 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 $130.0 million and $2.9 million as of March 31, 2015 and December 31, 2014, respectively.

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 calculated the excess of each reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. As of March 31, 2015, there have been no events or changes in circumstance which would indicate impairment of our goodwill.

NOTE 7. FAIR VALUE (Continued)

Intangible Assets. The Company assesses indefinite-lived intangible assets for impairment annually in the third 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 $84.3 million as of March 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 value over its undiscounted future cash flows. If the carrying value is not recoverable, an impairment loss is recorded based on the amount by which the carrying value 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 March 31, 2015, there have been no events or changes in circumstance which would indicate impairment of our intangible assets.

Property, Plant and Equipment. The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable. For the three months ended March 31, 2015 and the year ended December 31, 2014, there were no indicators of impairment.

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allows for the recovery of the remaining book value of retired plant assets. We will retire Taconite Harbor Unit 3 and convert Laskin to natural gas in the second quarter of 2015, which actions were included in our 2013 Integrated Resource Plan approved by the MPUC in a November 2013 order. Accordingly, we do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin.

- 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

Regulatory Matters

3 Months Ended

Mar. 31, 2015

Regulatory Matters [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.

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a 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 the remaining 15 Minnesota municipal customers and SWL&P 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 our 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. The contract terms include a termination clause requiring a three-year notice to terminate. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2025. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

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 23, 2015, 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.

NOTE 8. REGULATORY MATTERS (Continued)

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 our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. In April 2014 and November 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we 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 our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014, installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $260 million of which $162 million was spent through March 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 a July 2014 order. In November 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills.

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 with respect to the GNTL. In a January 2014 order, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On March 16, 2015, the administrative law judge recommended the MPUC grant a Certificate of Need for construction of the GNTL. 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. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016 and to be completed in 2020.

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 8. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	March 31, 2015		December 31, 2014
Millions
Current Regulatory Assets (a)
Deferred Fuel		$15.6		$16.3
Total Current Regulatory Assets	15.6		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	220.0		223.9
Cost Recovery Riders (c)	63.4		59.7
Income Taxes	46.8		46.6
Asset Retirement Obligations	18.6		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	4.2		4.3
Total Non-Current Regulatory Assets	358.0		357.3
Total Regulatory Assets		$373.6		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$46.9		$42.9
Plant Removal Obligations	22.0		22.8
Income Taxes	13.5		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	2.9		3.5
Other	15.9		11.6
Total Non-Current Regulatory Liabilities		$101.2		$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, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. (See Note 15. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are due to capital expenditures related to our 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.

Investment in ATC

3 Months Ended

Mar. 31, 2015

Investment in ATC [Abstract]

Investment in ATC [Text Block]

INVESTMENT IN ATC

Our wholly-owned subsidiary, Rainy River Energy, 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. ATC rates are based on a FERC-approved 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of March 31, 2015, our equity investment in ATC was $122.3 million ($121.1 million at December 31, 2014). In the first three months of 2015, we invested $0.4 million in ATC, and on April 29, 2015, we invested an additional $0.4 million. We expect to make additional investments of approximately $1.1 million in 2015.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2014		$121.1
Cash Investments	0.4
Equity in ATC Earnings	3.9
Distributed ATC Earnings	(3.1		)
Equity Investment Balance as of March 31, 2015		$122.3

NOTE 9. INVESTMENT IN ATC (Continued)

ATC’s summarized financial data for the three months ended March 31, 2015 and 2014, is as follows:



	Three Months Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2015		2014
Millions
Revenue	$152.4		$163.3
Operating Expense	80.0		78.6
Other Expense	24.4		21.6
Net Income	$48.0		$63.1
ALLETE’s Equity in Net Income		$3.9	$5.1

Our equity earnings in ATC for the three months ended March 31, 2015 were $3.9 million and reflected a $1.4 million reduction related to complaints filed with the FERC by several customer groups located within the MISO service area; of the $1.4 million reduction, $1.1 million was attributable to ATC’s change in estimate of a refund liability recorded in a previous period. 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. 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).

Short-Term and Long-Term Debt	3 Months Ended
Short-Term and Long-Term Debt	Mar. 31, 2015
Short-Term and Long-Term Debt [Abstract]
Short-Term and Long-Term Debt [Text Block]	SHORT-TERM AND LONG-TERM DEBT Short-Term Debt. As of March 31, 2015, total short-term debt outstanding was $122.6 million ($104.4 million as of December 31, 2014) and consisted of long-term debt due within one year and notes payable. Long-Term Debt. No long-term debt was issued in the first three months of 2015. As of March 31, 2015, total long-term debt outstanding was $1,253.8 million ($1,272.8 million as of December 31, 2014). Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of March 31, 2015, our ratio was approximately 0.44 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 March 31, 2015, ALLETE was in compliance with its financial covenants.

Other Income (Expense)

3 Months Ended

Mar. 31, 2015

Other Income (Expense) [Abstract]

Other Income (Expense) [Text Block]

OTHER INCOME (EXPENSE)



	Three Months Ended
	March 31,
	2015		2014
Millions
AFUDC–Equity		$0.9		$1.8
Investments and Other Income	0.2		0.2
Total Other Income		$1.1		$2.0

Income Tax Expense

3 Months Ended

Mar. 31, 2015

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Three Months Ended
	March 31,
	2015			2014
Millions
Current Tax Expense
Federal (a)	—			—
State (a)	$0.1			—
Total Current Tax Expense	$0.1			—
Deferred Tax Expense
Federal		$4.8			$6.3
State	1.5			2.7
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Tax Expense	6.1			8.8
Total Income Tax Expense		$6.2			$8.8


(a)	For the three months ended March 31, 2015 and 2014, the federal and state current tax expense was minimal due to the utilization of NOL carryforwards from prior periods. The NOL carryforwards resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

For the three months ended March 31, 2015, the effective tax rate was 13.4 percent (20.7 percent for the three months ended March 31, 2014). The decrease in the effective tax rate from March 31, 2014, was primarily due to increased production tax credits. The effective rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC–Equity, investment tax credits, production tax credits and depletion.

Uncertain Tax Positions. As of March 31, 2015, we had gross unrecognized tax benefits of $2.0 million ($2.0 million as of December 31, 2014). Of the total gross unrecognized tax benefits, $0.3 million represents the amount of unrecognized tax benefits included in the Consolidated Balance Sheet that, if recognized, would favorably impact the effective income tax rate. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

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 is no longer subject to federal examination for years before 2011, or state examination for years before 2010.

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2015

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

Reclassifications Out of Accumulated Other Comprhensive Income (Loss) [Text Block]

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2015 and 2014, were as follows:



	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
Three Months Ended March 31, 2015
Beginning Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)	$(0.1)	$(21.1)
Other Comprehensive Income Before Reclassifications	0.2		—	0.1	0.3
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1	)	0.3	—	0.2
Net Other Comprehensive Income	0.1		0.3	0.1	0.5
Ending Accumulated Other Comprehensive Loss	$(0.2)		$(20.4)	—	$(20.6)

Three Months Ended March 31, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)	$(0.3)	$(17.1)
Other Comprehensive Income Before Reclassifications	—		—	—	—
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		0.3	—	0.3
Net Other Comprehensive Income	—		0.3	—	0.3
Ending Accumulated Other Comprehensive Loss	$(0.1)		$(16.4)	$(0.3)	$(16.8)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014, were as follows:



	Three Months Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	March 31,		March 31,
	2015		2014
Millions
Unrealized Gains on Available-for-sale Securities	—		—
Income Taxes (a)	$0.1		—
Total, Net of Income Taxes	$0.1		—

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (b)	$0.1		$0.1
Actuarial Gains and Losses (b)	(0.6	)	(0.6	)
Total	(0.5	)	(0.5	)
Income Taxes (a)	0.2		0.2
Total, Net of Income Taxes	$(0.3)		$(0.3)
Total Reclassifications	$(0.2)		$(0.3)


(a)	Included in Income Tax Expense on our Consolidated Statement of Income.


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

- 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

Earnings Per Share and Common Stock

3 Months Ended

Mar. 31, 2015

Earnings Per Share and Common Stock [Abstract]

Earnings Per Share and Common Stock [Text Block]

EARNINGS PER SHARE AND COMMON STOCK

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). For the three months ended March 31, 2015 and 2014, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share.



			2015					2014
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Three months ended March 31,
Net Income Attributable to ALLETE		$39.9			$39.9		$33.5			$33.5
Average Common Shares	46.9		0.2	47.1		41.4		0.2	41.6
Earnings Per Share		$0.85			$0.85		$0.81			$0.80

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 in exchange 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 three months ended March 31, 2015. For the three months ended March 31, 2014, ALLETE contributed 0.4 million shares of ALLETE common stock to its pension plan. 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, and had an aggregate value of $19.5 million when contributed.

Pension and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2015

Pension and Other Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2015			2014			2015			2014
Millions
Three months ended March 31,
Service Cost		$2.5			$2.1			$1.1			$0.9
Interest Cost	7.5			7.4			1.8			1.8
Expected Return on Plan Assets	(10.2		)	(9.6		)	(2.7		)	(2.6		)
Amortization of Prior Service Costs (Credits)	—			0.1			(0.8		)	(0.6		)
Amortization of Net Loss	4.5			3.6			0.1			0.1
Net Periodic Benefit Expense (Income)		$4.3			$3.6		$(0.5)			$(0.4)

Employer Contributions. For the three months ended March 31, 2015, no contributions were made to our defined benefit pension plan ($19.5 million for the three months ended March 31, 2014); we do not expect to make any contributions to our defined benefit pension plan in 2015. For the three months ended March 31, 2015 and 2014, we made no contributions to our other postretirement benefit plan; we do not expect to make any contributions to our other postretirement benefit plan in 2015.

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 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 our 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 Minnesota Power’s entitlement to Unit output. Our 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 March 31, 2015, Square Butte had total debt outstanding of $390.9 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2015 through 2019, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during the three months ended March 31, 2015, was $19.2 million ($16.8 million for the three months ended March 31, 2014). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $2.5 million during the three months ended March 31, 2015 ($2.5 million for the three months ended March 31, 2014). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced in June 2014. Under the power sales agreement, Minnesota Power is selling a portion of its output 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. In 2015, Minnesota Power’s portion of output sold to Minnkota Power is approximately 28 percent (23 percent commencing on June 1, 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 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 we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that 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. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase 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.

NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The 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. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 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 long-term 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 agreement 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.)

Great River Energy PPAs. In August 2014 and January 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 and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both 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.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through December 2015. Minnesota Power is currently in discussions regarding the extension of our coal supply contracts beyond 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2018. Our minimum annual payment obligation under these supply and transportation agreements is $42.3 million for the remainder of 2015, $27.0 million in 2016, $27.6 million in 2017, and $28.4 million in 2018. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term, which expires in 2027. BNI Coal 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 $13.4 million in 2015, $11.4 million in 2016, $10.6 million in 2017, $9.5 million in 2018, $8.3 million in 2019 and $27.3 million thereafter.

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 23, 2015, 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.

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.

NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

On April 2, 2015, the CapX2020 transmission line project from Fargo, North Dakota to St. Cloud, Minnesota was completed and placed into service. Minnesota Power previously participated in two additional CapX2020 projects which were completed and placed into 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 elect to 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 with respect to the GNTL. In a January 2014 order, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On March 16, 2015, the administrative law judge recommended the MPUC grant a Certificate of Need for construction of the GNTL. 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. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016 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 by both Congress and the EPA. Minnesota Power’s fossil fuel facilities will likely be subject to regulation under these proposals. Our intention is to reduce our exposure to these requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

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. Due to expected future restrictive environmental requirements imposed through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will 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.

NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 Units 1, 2, 3 and 4 and Laskin Unit 2 between the years of 1981 to 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 to an existing Boswell scrubber. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. We are evaluating our options with regard to Boswell Units 1 and 2 to comply with the Consent Decree and future anticipated environmental regulations. 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 five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NO_x reductions under the CSAPR ozone season control program. 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 will be allocated to facilities from each state’s annual budget and can be bought and sold.

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 CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be 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 must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $260 million through 2016, of which $162 million was spent through March 31, 2015. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015 to position the Company 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 Unit 3 retirement with MISO’s resource planning year.

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 must implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above, which is required to be completed by April 1, 2016 (see Mercury and Air Toxics Standards (MATS) Rule), will fulfill the requirements of the Minnesota Mercury Emissions Reduction Act.

NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT) became effective in December 2012. Major existing sources have 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 costs for complying with the final rule are not expected to be material at this time.

Proposed and Finalized 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 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 and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. In November 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time.

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. The EPA issued designations of 2012 fine particulate attainment status in December 2014. Minnesota retained attainment status; 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 will likely be in compliance with these new standards; however, the one-hour SO₂ NAAQS also may require the EPA to evaluate modeling data 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 new 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 has delayed completing the documents pending EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned 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 Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the 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 Band in October 2014, and the public comment period on the petition expired in November 2014. After the Band prepares responses to the comments, the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. 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 16. 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 is expected to finalize such rules by the summer of 2015. In the CPP, the EPA proposes to set state-specific goals for CO₂ emissions from the power sector. 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).

The EPA proposed that BSER is comprised of four 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, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers.

The EPA then established state goals, expressed as a carbon intensity target in CO₂ tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA.

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 8. Regulatory Matters.)

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

NOTE 16. 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 guidelines for steam electric power generating stations under the Clean Water Act. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the 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. We 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 coal ash at all five of its coal-fired 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 with a final publication date of 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, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case.

Other Matters.

ALLETE Clean Energy. In January 2014, ALLETE Clean Energy acquired three wind energy facilities–Lake Benton, Storm Lake II and Condon. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. In December 2014, ALLETE Clean Energy acquired a wind facility, Storm Lake I, which has a PPA in place for its entire output which expires in 2018. On April 15, 2015, ALLETE Clean Energy acquired wind facilities in southern Minnesota with PPAs in place for the entire output, which expire in 2018 and 2023. (See Note 4. Acquisitions.)

U.S. Water Services. As of March 31, 2015, U.S. Water Services has $3.2 million outstanding in stand-by letters of credit.

BNI Coal. As of March 31, 2015, BNI Coal had surety bonds outstanding of $49.5 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 Coal has secured a letter of credit for an additional $0.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $49.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

ALLETE Properties. As of March 31, 2015, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.1 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In 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 March 31, 2015, we owned 72 percent of the assessable land in the Town Center District (72 percent at December 31, 2014) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2014). At these ownership levels, our annual assessments 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.

Operations and Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Operations and Significant Accounting Policies [Abstract]
Inventories [Policy Text Block]	Inventories are stated at the lower of cost or market. Amounts removed from inventories in our Regulated Operations segment are recorded on an average cost basis. Amounts removed from inventories in our Investments and Other segment are recorded on an average cost, first-in, first-out or specific identification basis.
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 U.S. GAAP, goodwill is not amortized. The Company assesses whether there has been an impairment of goodwill annually in the third quarter 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 future 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, patents and non-compete agreements, which are amortized on a straight-line or accelerated basis with estimated useful lives ranging from less than 1 year to 23 years. We review other 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 third 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 future cash flow analysis.
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.
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 is effective beginning in the first quarter of 2015, and applies prospectively to new disposals and new classifications of disposal groups as held for sale. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows. 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. Early adoption is not permitted for public companies. On April 1, 2015, the FASB voted to propose a deferral of the effective date of the standard by one year which would make the guidance effective for the Company beginning in the first quarter of 2018. The FASB is expected to issue updated accounting guidance regarding the deferred effective date, subject to a 30-day comment period, in the second quarter of 2015. 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 in the 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. We are evaluating the impact of the adoption of this standard.
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 fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairments were recorded for the three months ended March 31, 2015 (none for the year ended December 31, 2014).
Long-Term Finance Receivables [Policy Text Block]	Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts.
Acquisition [Policy Text Block]	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. In connection with finalizing purchase price accounting, the Company recorded minor adjustments during the first quarter of 2015 to certain assets and liabilities, which are reflected in the table below. The result of these adjustments had no impact on the results of operations for the period ended March 31, 2015. Fair value measurements were valued primarily using the discounted cash flow method. The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to customer relationships, developed technologies, trademarks and trade names, and current and deferred income taxes; subsequent adjustments could impact the amount of goodwill recorded. 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 liabilities assumed at the date of acquisition. Fair value measurements were valued primarily using the replacement cost method
Derivatives [Policy Text Block]	Changes in the fair value of the Swap were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swap are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income related to the Swap will be recorded in earnings when the hedged transaction occurs or when it is probable it will not occur. Gains or losses on the interest rate hedging transaction are reflected as a component of Interest Expense on the Consolidated Statement of Income.
Fair Value Measurement [Policy Text Block]	Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized. 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). Descriptions of the three levels of the fair value hierarchy are discussed in Note 10. Fair Value to the Consolidated Financial Statements in our 2014 Form 10-K. 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 March 31, 2015, and December 31, 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 tables below.
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 Text Block]	We account for our investment in ATC under the equity method of accounting.
Earnings Per Share, Policy [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
Environmental Costs [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 charged to expense unless recoverable in rates from customers.

Operations and Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2015

Operations and Significant Accounting Policies [Abstract]

Inventories [Table Text Block]



Inventories	March 31, 2015			December 31, 2014
Millions
Regulated Operations Inventories
Fuel		$38.0			$29.0
Materials and Supplies	34.6			35.2
Total Regulated Operations Inventories	72.6			64.2
Investments and Other Inventories (a)
Materials and Supplies	16.3			16.3
Raw Materials	3.1			—
Work in Progress	1.0			—
Finished Goods	10.2			—
Reserve for Obsolescence	(0.5		)	—
Total Investments and Other Inventories	30.1			16.3
Total Inventories		$102.7			$80.5


(a)	Raw materials, Work in Progress, Finished Goods, and Reserve for Obsolescence presented are attributable to U.S. Water Services which was acquired February 10, 2015.

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	March 31, 2015		December 31, 2014
Millions
Deferred Fuel Adjustment Clause		$15.6		$16.3
Construction Costs for Development Project (a)	48.4		48.2
Restricted Cash (b)	5.6		2.7
Other	18.9		14.8
Total Prepayments and Other Current Assets		$88.5		$82.0


(a)	Construction Costs for Development Project relate to ALLETE Clean Energy’s acquisition in November 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 4. Acquisitions.)


(b)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.

Other Current and Non-Current Liabilities [Table Text Block]



Other Current Liabilities	March 31, 2015		December 31, 2014
Millions
Customer Deposits		$20.0		$19.7
Power Purchase Agreements (a)	18.9		19.4
Construction Deposits Received for Development Project (b)	54.3		54.3
Other	25.4		27.4
Total Other Current Liabilities		$118.6		$120.8


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)


(b)	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayments and Other Current Assets table and Note 4. Acquisitions.)



Other Non-Current Liabilities	March 31, 2015		December 31, 2014
Millions
Asset Retirement Obligation		$111.6		$109.2
Power Purchase Agreements (a)	106.3		110.7
Contingent Consideration (b)	35.8		—
Other	48.6		45.1
Total Other Non-Current Liabilities		$302.3		$265.0


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment to acquire the remaining ownership interest in U.S. Water Services. (See Note 4. Acquisitions and Note 7. Fair Value.)

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



Three Months Ended March 31,	2015		2014
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$15.3		$12.4
Cash Paid During the Period for Income Taxes		$0.1		$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(32.2)		$(22.6)
Capitalized Asset Retirement Costs	$1.2			$0.6
AFUDC–Equity		$0.9		$1.8
ALLETE Common Stock Contributed to the Pension Plan	—			$19.5
Contingent Consideration		$35.7	—

Business Segments (Tables)

3 Months Ended

Mar. 31, 2015

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
Three Months Ended March 31, 2015
Operating Revenue		$320.0			$262.8			$57.2
Fuel and Purchased Power	86.0			86.0			—
Transmission Services	14.9			14.9			—
Cost of Sales	31.2			4.5			26.7
Operating and Maintenance	79.7			58.7			21.0
Depreciation and Amortization	39.0			32.1			6.9
Taxes Other than Income Taxes	12.8			11.6			1.2
Operating Income	56.4			55.0			1.4
Interest Expense	(15.1		)	(13.0		)	(2.1		)
Equity Earnings in ATC	3.9			3.9			—
Other Income	1.1			0.9			0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	46.3			46.8			(0.5		)
Income Tax Expense	6.2			5.4			0.8
Net Income (Loss)	40.1			41.4			(1.3		)
Less: Non-Controlling Interest in Subsidiaries	0.2			—			0.2
Net Income (Loss) Attributable to ALLETE		$39.9			$41.4		$(1.5)

As of March 31, 2015
Total Assets		$4,580.1			$3,748.4			$831.7
Property, Plant and Equipment – Net		$3,319.2			$3,025.3			$293.9
Accumulated Depreciation		$1,367.0			$1,286.9			$80.1
Capital Additions		$57.3			$54.9			$2.4

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
Three Months Ended March 31, 2014
Operating Revenue		$296.5			$264.2			$32.3
Fuel and Purchased Power	96.2			96.2			—
Transmission Services	10.8			10.8			—
Cost of Sales	23.5			8.7			14.8
Operating and Maintenance	74.3			60.5			13.8
Depreciation and Amortization	32.2			28.8			3.4
Taxes Other than Income Taxes	11.2			10.2			1.0
Operating Income (Loss)	48.3			49.0			(0.7		)
Interest Expense	(12.8		)	(11.5		)	(1.3		)
Equity Earnings in ATC	5.1			5.1			—
Other Income	2.0			1.8			0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	42.6			44.4			(1.8		)
Income Tax Expense (Benefit)	8.8			10.5			(1.7		)
Net Income (Loss)	33.8			33.9			(0.1		)
Less: Non-Controlling Interest in Subsidiaries	0.3			—			0.3
Net Income (Loss) Attributable to ALLETE		$33.5			$33.9		$(0.4)

As of March 31, 2014
Total Assets		$3,749.2			$3,335.5			$413.7
Property, Plant and Equipment – Net		$2,905.1			$2,671.3			$233.8
Accumulated Depreciation		$1,266.7			$1,202.9			$63.8
Capital Additions		$195.2			$193.5			$1.7

Investments (Tables)

3 Months Ended

Mar. 31, 2015

Investments [Abstract]

Other Investments and ALLETE Properties [Table Text Block]



Other Investments	March 31, 2015		December 31, 2014
Millions
ALLETE Properties		$88.3		$88.2
Available-for-sale Securities (a)	19.3		18.9
Cash Equivalents	2.8		2.9
Other	4.3		4.4
Total Other Investments		$114.7		$114.4


(a)	As of March 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.4 million, in one year to less than three years was $1.7 million, in three years to less than five years was $3.0 million, and in five or more years was $5.9 million.

NOTE 3. INVESTMENTS (Continued)



ALLETE Properties	March 31, 2015		December 31, 2014
Millions
Land Inventory Beginning Balance		$83.8		$85.4
Cost of Sales	—		(2.2		)
Other	0.1		0.6
Land Inventory Ending Balance	83.9		83.8
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.2		1.2
Other	3.2		3.2
Total Real Estate Assets		$88.3		$88.2

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
	Cost	Gain	Loss	Fair Value
March 31, 2015	$19.8	$0.3	$0.8	$19.3
December 31, 2014	$19.6	$0.2	$0.9	$18.9

Acquisition (Table)

3 Months Ended

Mar. 31, 2015

Acquisition [Abstract]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Other Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
Other 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)	Other Current Liabilities included $7.5 million related to the current liabilities portion of the 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
Other 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 in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.


(c)	The purchase price accounting valued the non-controlling interest relating to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.



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
Goodwill (c)	127.1
Intangible Assets (d)	83.0
Other Non-Current Assets	0.2
Total Assets Acquired		$257.3
Liabilities Assumed
Other Current Liabilities		$18.7
Other Non-Current Liabilities	36.3
Total Liabilities Assumed		$55.0
Net Identifiable Assets Acquired		$202.3


(a)	Included in Inventories was $2.7 million of fair value adjustments relating to work in process 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 stand-by letters of credit.


(c)	Goodwill is largely attributable to strategic opportunities for growing U.S. Water Services and the benefits of the existing workforce. Goodwill of $3.2 million is deductible for tax purposes.


(d)	Intangible Assets include customer relationships, patents, non-compete agreements and trademarks and trade names. (See Note 5. Goodwill and Intangible Assets.)

Goodwill and Intangible Assets (Tables)

3 Months Ended

Mar. 31, 2015

Goodwill and Intangible Assets [Abstract]

Schedule of Goodwill [Table Text Block]

The following table summarizes changes to goodwill by business segment for the three months ended March 31, 2015:




	Investments and Other
Millions
Balance as of December 31, 2014		$2.9
Acquired Goodwill	127.1
Balance as of March 31, 2015		$130.0

Schedule of Intangible Assets [Table Text Block]

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



	December 31, 2014		Additions as a Result of Acquisitions		Amortization	March 31, 2015
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	—			$60.1	$0.5		$59.6
Developed Technology and Other (a)		$1.9	6.3		0.1	8.1
Total Definite-Lived Intangible Assets	1.9		66.4		0.6	67.7
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	—		16.6		n/a	16.6
Total Intangible Assets		$1.9		$83.0	$0.6		$84.3


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

Fair Value (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of March 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.3	—		—			$8.3
Available-for-sale – Corporate Debt Securities	—			$11.0	—		11.0
Cash Equivalents	2.8		—		—		2.8
Total Fair Value of Assets		$11.1		$11.0	—			$22.1

Liabilities:
Deferred Compensation (b)	—			$15.4	—			$15.4
Derivatives – Interest Rate Swap (c)	—		0.2		—		0.2
U.S. Water Services Contingent Consideration (b)	—		—			$35.8	35.8
Total Fair Value of Liabilities	—			$15.6		$35.8		$51.4
Total Net Fair Value of Assets (Liabilities)		$11.1	$(4.6)		$(35.8)		$(29.3)


(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.



	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 at December 31, 2014	—
Recognition of U.S. Water Services Contingent Consideration	$35.7
Accretion Expense	0.1
Balance at March 31, 2015		$35.8

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
March 31, 2015	$1,376.1	$1,525.4
December 31, 2014	$1,373.5	$1,484.5

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2015

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	March 31, 2015		December 31, 2014
Millions
Current Regulatory Assets (a)
Deferred Fuel		$15.6		$16.3
Total Current Regulatory Assets	15.6		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	220.0		223.9
Cost Recovery Riders (c)	63.4		59.7
Income Taxes	46.8		46.6
Asset Retirement Obligations	18.6		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	4.2		4.3
Total Non-Current Regulatory Assets	358.0		357.3
Total Regulatory Assets		$373.6		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$46.9		$42.9
Plant Removal Obligations	22.0		22.8
Income Taxes	13.5		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	2.9		3.5
Other	15.9		11.6
Total Non-Current Regulatory Liabilities		$101.2		$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, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. (See Note 15. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are due to capital expenditures related to our 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.

Investment in ATC (Tables)

3 Months Ended

Mar. 31, 2015

Investment in ATC [Abstract]

ALLETE's Investment in ATC [Table Text Block]



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2014		$121.1
Cash Investments	0.4
Equity in ATC Earnings	3.9
Distributed ATC Earnings	(3.1		)
Equity Investment Balance as of March 31, 2015		$122.3

NOTE 9. INVESTMENT IN ATC (Continued)

ATC’s summarized financial data for the three months ended March 31, 2015 and 2014, is as follows:



	Three Months Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2015		2014
Millions
Revenue	$152.4		$163.3
Operating Expense	80.0		78.6
Other Expense	24.4		21.6
Net Income	$48.0		$63.1
ALLETE’s Equity in Net Income		$3.9	$5.1

Other Income (Expense) (Tables)

3 Months Ended

Mar. 31, 2015

Other Income (Expense) [Abstract]

Other Income (Expense) [Table Text Block]



	Three Months Ended
	March 31,
	2015		2014
Millions
AFUDC–Equity		$0.9		$1.8
Investments and Other Income	0.2		0.2
Total Other Income		$1.1		$2.0

Income Tax Expense (Tables)

3 Months Ended

Mar. 31, 2015

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



	Three Months Ended
	March 31,
	2015			2014
Millions
Current Tax Expense
Federal (a)	—			—
State (a)	$0.1			—
Total Current Tax Expense	$0.1			—
Deferred Tax Expense
Federal		$4.8			$6.3
State	1.5			2.7
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Tax Expense	6.1			8.8
Total Income Tax Expense		$6.2			$8.8


(a)	For the three months ended March 31, 2015 and 2014, the federal and state current tax expense was minimal due to the utilization of NOL carryforwards from prior periods. The NOL carryforwards resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

Reclassificiations out of Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2015

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

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

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2015 and 2014, were as follows:



	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
Three Months Ended March 31, 2015
Beginning Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)	$(0.1)	$(21.1)
Other Comprehensive Income Before Reclassifications	0.2		—	0.1	0.3
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1	)	0.3	—	0.2
Net Other Comprehensive Income	0.1		0.3	0.1	0.5
Ending Accumulated Other Comprehensive Loss	$(0.2)		$(20.4)	—	$(20.6)

Three Months Ended March 31, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)	$(0.3)	$(17.1)
Other Comprehensive Income Before Reclassifications	—		—	—	—
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		0.3	—	0.3
Net Other Comprehensive Income	—		0.3	—	0.3
Ending Accumulated Other Comprehensive Loss	$(0.1)		$(16.4)	$(0.3)	$(16.8)

Amount Reclassified from Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014, were as follows:



	Three Months Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	March 31,		March 31,
	2015		2014
Millions
Unrealized Gains on Available-for-sale Securities	—		—
Income Taxes (a)	$0.1		—
Total, Net of Income Taxes	$0.1		—

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (b)	$0.1		$0.1
Actuarial Gains and Losses (b)	(0.6	)	(0.6	)
Total	(0.5	)	(0.5	)
Income Taxes (a)	0.2		0.2
Total, Net of Income Taxes	$(0.3)		$(0.3)
Total Reclassifications	$(0.2)		$(0.3)


(a)	Included in Income Tax Expense on our Consolidated Statement of Income.


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

Earnings Per Share and Common Stock (Tables)

3 Months Ended

Mar. 31, 2015

Earnings Per Share and Common Stock [Abstract]

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



			2015					2014
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Three months ended March 31,
Net Income Attributable to ALLETE		$39.9			$39.9		$33.5			$33.5
Average Common Shares	46.9		0.2	47.1		41.4		0.2	41.6
Earnings Per Share		$0.85			$0.85		$0.81			$0.80

Pension and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2015

Pension and Other Postretirement Benefit Plans [Abstract]

Components of Net Periodic Benefit Expense [Table Text Block]



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2015			2014			2015			2014
Millions
Three months ended March 31,
Service Cost		$2.5			$2.1			$1.1			$0.9
Interest Cost	7.5			7.4			1.8			1.8
Expected Return on Plan Assets	(10.2		)	(9.6		)	(2.7		)	(2.6		)
Amortization of Prior Service Costs (Credits)	—			0.1			(0.8		)	(0.6		)
Amortization of Net Loss	4.5			3.6			0.1			0.1
Net Periodic Benefit Expense (Income)		$4.3			$3.6		$(0.5)			$(0.4)

Operations and Significant Accounting Policies - Reclassifications (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014
Consolidated Balance Sheet [Member] \| Property, Plant and Equipment - Net to Goodwill and Intangible Assets - Net [Member]
Reclassifications [Line Items]
Reclassification Adjustment		$ 1.6
Consolidated Balance Sheet [Member] \| Other Non-Current Assets to Goodwill and Intangible Assets - Net [Member]
Reclassifications [Line Items]
Reclassification Adjustment		3.2
Consolidated Balance Sheet [Member] \| Total Assets [Member]
Reclassifications [Line Items]
Reclassification Adjustment		$ 0.0
Consolidated Statement of Income [Member] \| Operating and Maintenance Expenses to Cost of Sales [Member]
Reclassifications [Line Items]
Reclassification Adjustment	$ 23.5
Consolidated Statement of Income [Member] \| Operating and Maintenance Expenses to Transmission Services [Member]
Reclassifications [Line Items]
Reclassification Adjustment	10.8
Consolidated Statement of Income [Member] \| Operating and Maintenance Expenses to Taxes Other than Income Taxes [Member]
Reclassifications [Line Items]
Reclassification Adjustment	11.2
Consolidated Statement of Income [Member] \| Operating Income [Member]
Reclassifications [Line Items]
Reclassification Adjustment	0.0
Consolidated Statement of Income [Member] \| Net Income [Member]
Reclassifications [Line Items]
Reclassification Adjustment	0.0
Consolidated Statement of Income [Member] \| Net Income Attributable to ALLETE [Member]
Reclassifications [Line Items]
Reclassification Adjustment	0.0
Consolidated Statement of Cash Flows [Member] \| Changes in Regulatory and Other Non-Current Liabilities to Amortization of Power Purchase Agreements [Member]
Reclassifications [Line Items]
Reclassification Adjustment	2.3
Consolidated Statement of Cash Flows [Member] \| Operating Activities [Member]
Reclassifications [Line Items]
Reclassification Adjustment	0.0
Consolidated Statement of Cash Flows [Member] \| Investing Activities [Member]
Reclassifications [Line Items]
Reclassification Adjustment	0.0
Consolidated Statement of Cash Flows [Member] \| Financing Activities [Member]
Reclassifications [Line Items]
Reclassification Adjustment	$ 0.0

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

3 Months Ended

Mar. 31, 2015

Dec. 31, 2014

Business Segments [Line Items]

Total Inventories

$ 102.7

$ 80.5

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

15.6

16.3

Construction Costs for Development Project

^[1]

48.4

48.2

Restricted Cash

^[2]

5.6

2.7

Other

18.9

14.8

Total Prepayments and Other Current Assets

88.5

82.0

Other Non-Current Assets [Abstract]

Restricted Cash

5.3

Other Current Liabilites [Abstract]

Customer Deposits

20.0

19.7

Power Purchase Agreements

^[3]

18.9

19.4

Construction Deposits Received for Development Project

^[4]

54.3

Other

25.4

27.4

Total Other Current Liabilities

118.6

120.8

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

111.6

109.2

Power Purchase Agreements

^[5]

106.3

110.7

Contingent Consideration

^[6]

35.8

0.0

Other

48.6

45.1

Total Other Non-Current Liabilities

302.3

265.0

Regulated Operations [Member]

Business Segments [Line Items]

Fuel

38.0

29.0

Materials and Supplies

34.6

35.2

Total Inventories

72.6

64.2

Investments and Other [Member]

Business Segments [Line Items]

Materials and Supplies

16.3

Raw Materials

3.1

^[7]

0.0

Work in Progress

1.0

^[7]

0.0

Finished Goods

10.2

^[7]

0.0

Reserve for Obsolescence

(0.5)

^[7]

0.0

Total Inventories

$ 30.1

$ 16.3

Minimum [Member]

Finite-Lived Intangible Assets [Line Items]

Estimated Useful Life

1 year

Maximum [Member]

Finite-Lived Intangible Assets [Line Items]

Estimated Useful Life

23 years

[1]	Construction Costs for Development Project relate to ALLETE Clean Energy’s acquisition in November 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 4. Acquisitions.)
[2]	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.
[3]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)
[4]	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayments and Other Current Assets table and Note 4. Acquisitions.)
[5]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)
[6]	Contingent Consideration relates to the estimated fair value of the earnings-based payment to acquire the remaining ownership interest in U.S. Water Services. (See Note 4. Acquisitions and Note 7. Fair Value.)
[7]	Raw materials, Work in Progress, Finished Goods, and Reserve for Obsolescence presented are attributable to U.S. Water Services which was acquired February 10, 2015.

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized	$ 15.3	$ 12.4
Cash Paid During the Period for Income Taxes	0.1	0.2
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	(32.2)	(22.6)
Capitalized Asset Retirement Costs	1.2	0.6
AFUDC–Equity	0.9	1.8
ALLETE Common Stock Contributed to the Pension Plan	0.0	19.5
Contingent Consideration	$ 35.7	$ 0.0

Business Segments (Details) $ in Millions	3 Months Ended
Business Segments (Details) $ in Millions	Mar. 31, 2015 USD ($) a	Mar. 31, 2014 USD ($)	Dec. 31, 2014 USD ($)
Business Segments [Line Items]
Operating Revenue	$ 320.0	$ 296.5
Fuel and Purchased Power	86.0	96.2
Transmission Services	14.9	10.8
Cost of Sales	31.2	23.5
Operating and Maintenance	79.7	74.3
Depreciation and Amortization	39.0	32.2
Taxes Other than Income Taxes	12.8	11.2
Operating Income (Loss)	56.4	48.3
Interest Expense	(15.1)	(12.8)
Equity Earnings in ATC	3.9	5.1
Other Income	1.1	2.0
Income (Loss) Before Non-Controlling Interest and Income Taxes	46.3	42.6
Income Tax Expense (Benefit)	6.2	8.8
Net Income (Loss)	40.1	33.8
Less: Non-Controlling Interest in Subsidiaries	0.2	0.3
Net Income (Loss) Attributable to ALLETE	39.9	33.5
Total Assets	4,580.1	3,749.2	$ 4,360.8
Property, Plant and Equipment - Net	3,319.2	2,905.1	$ 3,284.8
Accumulated Depreciation	1,367.0	1,266.7
Capital Additions	57.3	195.2
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue	262.8	264.2
Fuel and Purchased Power	86.0	96.2
Transmission Services	14.9	10.8
Cost of Sales	4.5	8.7
Operating and Maintenance	58.7	60.5
Depreciation and Amortization	32.1	28.8
Taxes Other than Income Taxes	11.6	10.2
Operating Income (Loss)	55.0	49.0
Interest Expense	(13.0)	(11.5)
Equity Earnings in ATC	3.9	5.1
Other Income	0.9	1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	46.8	44.4
Income Tax Expense (Benefit)	5.4	10.5
Net Income (Loss)	41.4	33.9
Less: Non-Controlling Interest in Subsidiaries	0.0	0.0
Net Income (Loss) Attributable to ALLETE	41.4	33.9
Total Assets	3,748.4	3,335.5
Property, Plant and Equipment - Net	3,025.3	2,671.3
Accumulated Depreciation	1,286.9	1,202.9
Capital Additions	$ 54.9	193.5
Investments and Other [Member]
Business Segments [Line Items]
Land in Minnesota (in acres) \| a	5,000
Operating Revenue	$ 57.2	32.3
Fuel and Purchased Power	0.0	0.0
Transmission Services	0.0	0.0
Cost of Sales	26.7	14.8
Operating and Maintenance	21.0	13.8
Depreciation and Amortization	6.9	3.4
Taxes Other than Income Taxes	1.2	1.0
Operating Income (Loss)	1.4	(0.7)
Interest Expense	(2.1)	(1.3)
Equity Earnings in ATC	0.0	0.0
Other Income	0.2	0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	(0.5)	(1.8)
Income Tax Expense (Benefit)	0.8	(1.7)
Net Income (Loss)	(1.3)	(0.1)
Less: Non-Controlling Interest in Subsidiaries	0.2	0.3
Net Income (Loss) Attributable to ALLETE	(1.5)	(0.4)
Total Assets	831.7	413.7
Property, Plant and Equipment - Net	293.9	233.8
Accumulated Depreciation	80.1	63.8
Capital Additions	$ 2.4	$ 1.7

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

3 Months Ended

12 Months Ended

Mar. 31, 2015

Dec. 31, 2014

Investments [Abstract]

ALLETE Properties

$ 88.3

$ 88.2

Available-for-sale Securities

^[1]

19.3

18.9

Cash Equivalents

2.8

2.9

Other

4.3

4.4

Total Other Investments

114.7

114.4

Available-for-sale Corporate Debt Securities, Maturities, One Year or Less

0.4

Available-for-sale Corporate Debt Securities, Maturities, More than One Year to Less than Three Years

1.7

Available-for-sale Corporate Debt Securities, Maturities, Three Years to Less than Five Years

3.0

Available-for-sale Corporate Debt Securities, Maturities, Five Years or More

5.9

ALLETE Properties [Rollforward]

Land Inventory Beginning Balance

83.8

85.4

Cost of Sales

0.0

(2.2)

Other

0.1

0.6

Land Inventory Ending Balance

83.9

83.8

Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)

1.2

Other

3.2

Impairment of Real Estate

0.0

Long-Term Finance Receivable, Allowance

$ 0.6

[1]	As of March 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.4 million, in one year to less than three years was $1.7 million, in three years to less than five years was $3.0 million, and in five or more years was $5.9 million.

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

Mar. 31, 2015

Dec. 31, 2014

Available-for-sale Securities [Abstract]

Cost

$ 19.8

$ 19.6

Gross Unrealized Gain

0.3

0.2

Gross Unrealized Loss

0.8

0.9

Fair Value

^[1]

$ 19.3

$ 18.9

[1]	As of March 31, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.4 million, in one year to less than three years was $1.7 million, in three years to less than five years was $3.0 million, and in five or more years was $5.9 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

Investments - Investments Parenthetical (Details) - USD ($) $ in Millions	Mar. 31, 2015	Dec. 31, 2014
Investments Parentheticals [Abstract]
Long-Term Finance Receivable, Allowance	$ 0.6	$ 0.6

Acquisitions (Details)	3 Months Ended	12 Months Ended
Acquisitions (Details)	Mar. 31, 2015	Dec. 31, 2014
Acquisitions [Abstract]
Business Combination, Reason for Business Combinations	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.
Business Acquisition, Pro Forma Information	not significant	not significant

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

3 Months Ended

Feb. 10, 2015

Mar. 31, 2015

Dec. 31, 2014

Liabilities [Abstract]

Restricted Cash

^[1]

$ 5.6

$ 2.7

U.S. Water Services [Member]

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Feb. 10, 2015

Business Acquisition, Name of Acquired Entity

U.S. Water Services

Business Acquisition, Consideration Transferred

$ 202.3

Payments to Acquire Businesses, Gross

$ 166.6

Business Acquisition, Percentage of Voting Interests Acquired

87.00%

Business Acquisition, Contingent Consideration, Liability

$ 35.7

Business Acquisition, Percent of Results of Operations Reflected in Income Statement

100.00%

Business Acquisition, Effective Percentage of Business Acquired

100.00%

Assets [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

Goodwill

^[4]

127.1

Intangible Assets

^[5]

83.0

Other Non-Current Assets

0.2

Total Assets Acquired

257.3

Liabilities [Abstract]

Other Current Liabilities

18.7

Other Non-Current Liabilities

36.3

Total Liabilities and Non-Controlling Interest Assumed

55.0

Net Identifiable Assets Acquired

202.3

Fair Value Adjustments for Work in Process and Finished Goods

2.7

Fair Value of Sales Backlog

1.6

Restricted Cash

2.1

Business Acquisition, Goodwill, Expected Tax Deductible Amount

$ 3.2

Business Acquisition, Acquisition Related Costs

$ 3.0

[1]	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.
[2]	Included in Inventories was $2.7 million of fair value adjustments relating to work in process 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 stand-by letters of credit.
[4]	Goodwill is largely attributable to strategic opportunities for growing U.S. Water Services and the benefits of the existing workforce. Goodwill of $3.2 million is deductible for tax purposes.
[5]	Intangible Assets include customer relationships, patents, non-compete agreements and trademarks and trade names. (See Note 5. Goodwill and Intangible Assets.)

Acquisitions - Chanarambie/Viking (Details) - Chanarambie/Viking [Member] - Subsequent Event [Member] $ in Millions	Apr. 15, 2015 USD ($) MW
Business Acquisition [Line Items]
Business Acquisition, Effective Date of Acquisition	Apr. 15, 2015
Business Acquisition, Name of Acquired Entity	Chanarambie/Viking
Payments to Acquire Businesses, Gross \| $	$ 47.5
Generating Capacity (MW)	97.5
Chanarambie/Viking PPA (expires 2018) [Member]
Business Acquisition [Line Items]
Generating Capacity (MW)	12
Chanarambie/Viking PPA (expires 2023) [Member]
Business Acquisition [Line Items]
Generating Capacity (MW)	85.5

Acquisitions - Armenia Mountain (Details) - Armenia Mountain [Member] - Subsequent Event [Member] $ in Millions	Apr. 30, 2015 USD ($) MW
Business Acquisition [Line Items]
Member's Interest Purchase Agreement, Name of Business to be Acquired	Armenia Mountain
Member's Interest Purchase Agreement, Consideration \| $	$ 108.0
Member's Interest Purchase Agreement, Percent Ownership to be Acquired	100.00%
Generating Capacity (MW) \| MW	100.5

Acquisitions - ACE Wind Acquisition (Details)
$ in Millions

3 Months Ended

Feb. 11, 2014

USD ($)

Jan. 30, 2014

USD ($)

Mar. 31, 2015

USD ($)

Mar. 31, 2014

Dec. 31, 2014

USD ($)

Liabilities [Abstract]

Power Purchase Agreements

^[1]

$ 106.3

$ 110.7

Power Purchase Agreements

^[2]

$ 18.9

$ 19.4

Non-Controlling Interest, Decrease from Purchase of Interests

$ 6.0

Armenia Mountain [Member]

Liabilities [Abstract]

Purchase option

$ 0.3

ACE Wind [Member]

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Jan. 30, 2014

Payments to Acquire Businesses, Gross

26.9

Assets [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 [Abstract]

Other Current Liabilities

^[4]

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

^[5]

7.1

Total Liabilities and Non-Controlling Interest Assumed

155.6

Net Identifiable Assets Acquired

26.9

Goodwill

2.9

Business Acquisition, Goodwill, Expected Tax Deductible Amount

0.0

Power Purchase Agreements

$ 12.4

Lake Benton [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Lake Benton

Generating Capacity (MW) | MW

104

Storm Lake II [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Storm Lake II

Generating Capacity (MW) | MW

Condon [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Condon

Generating Capacity (MW) | MW

[1]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)
[2]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)
[3]	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[4]	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.
[5]	The purchase price accounting valued the non-controlling interest relating to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.

Acquisitions - Wind Development Project (Details)
$ in Millions

3 Months Ended

Apr. 15, 2015

USD ($)

Nov. 20, 2014

USD ($)

Dec. 31, 2014

USD ($)

Mar. 31, 2015

USD ($)

Assets [Abstract]

Construction Costs for Development Project

^[1]

$ 48.2

$ 48.4

Liabilities [Abstract]

Customer Deposits Received for Development Project

^[2]

$ 54.3

Wind Development Project [Member]

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Nov. 20, 2014

Payments to Acquire Businesses, Gross

$ 27.0

Generating Capacity (MW) | MW

107

Contractual Sales Price

200.0

Assets [Abstract]

Cash and Cash Equivalents

3.6

Construction Costs for Development Project

23.4

$ 48.2

Goodwill

0.0

Liabilities [Abstract]

Customer Deposits Received for Development Project

$ 54.3

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

$ 0.0

Subsequent Event [Member] | Wind Development Project [Member]

Liabilities [Abstract]

Increase (Decrease) in Customer Advances

$ 50.0

[1]	Construction Costs for Development Project relate to ALLETE Clean Energy’s acquisition in November 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 4. Acquisitions.)
[2]	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayments and Other Current Assets table and Note 4. Acquisitions.)

Acquisitions - Storm Lake I (Details)
$ in Millions

3 Months Ended

Dec. 17, 2014

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Liabilities [Abstract]

Power Purchase Agreements

^[1]

$ 106.3

$ 110.7

Power Purchase Agreement - Current

^[2]

$ 18.9

$ 19.4

Storm Lake I [Member]

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Dec. 17, 2014

Business Acquisition, Name of Acquired Entity

Storm Lake I

Payments to Acquire Businesses, Gross

$ 15.1

Generating Capacity (MW) | MW

108

Assets [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 [Abstract]

Other Current Liabilities

^[4]

8.2

Power Purchase Agreements

23.5

Other Non-Current Liabilities

17.0

Total Liabilities and Non-Controlling Interest Assumed

48.7

Net Identifiable Assets Acquired

15.1

Restricted Cash and Investments, Noncurrent

$ 0.4

Goodwill Description

immaterial

Power Purchase Agreement - Current

$ 7.5

[1]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. Acquisitions.)
[2]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 4. 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]	Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.

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

3 Months Ended

Mar. 31, 2015

Dec. 31, 2014

Intangible Assets [Abstract]

Definite-Lived Intangible Assets

$ 67.7

$ 1.9

Definite-Lived Intangible Assets, Additions as a Result of Acquisitions

66.4

Definite-Lived Intangible Assets, Amortization

0.6

Total Intangible Assets

84.3

1.9

Total Intangible Assets, Additions as a Result of Acquisitions

83.0

Definite-Lived Intangible Assets, Fiscal Year Amortization Expense [Abstract]

Definite-Lived Intangible Assets, Amortization Expense, Remainder of 2015

3.6

Definite-Lived Intangible Assets, Amortization Expense, 2016

4.3

Definite-Lived Intangible Assets, Amortization Expense, 2017

4.2

Definite-Lived Intangible Assets, Amortization Expense, 2018

4.1

Definite-Lived Intangible Assets, Amortization Expense, 2019

4.0

Definite-Lived Intangible Assets, Amortization Expense, 2020 and Thereafter

$ 47.5

Minimum [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Asset, Useful Life

1 year

Maximum [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Asset, Useful Life

23 years

Weighted Average [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Asset, Useful Life

21 years

Trademarks and Trade Names [Member]

Intangible Assets [Abstract]

Indefinite-Lived Intangible Assets

$ 16.6

0.0

Indefinite-lived Intangible Assets, Additions as a Result of Acquisitions

16.6

Customer Relationships [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets

59.6

0.0

Definite-Lived Intangible Assets, Additions as a Result of Acquisitions

60.1

Definite-Lived Intangible Assets, Amortization

$ 0.5

Definite-Lived Intangible Asset, Useful Life

23 years

Developed Technology and Other [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets

^[1]

$ 8.1

$ 1.9

Definite-Lived Intangible Assets, Additions as a Result of Acquisitions

^[1]

6.3

Definite-Lived Intangible Assets, Amortization

^[1]

$ 0.1

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

Intangible Assets [Abstract]

Definite-Lived Intangible Asset, Useful Life

1 year

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

Intangible Assets [Abstract]

Definite-Lived Intangible Asset, Useful Life

14 years

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

Intangible Assets [Abstract]

Definite-Lived Intangible Asset, Useful Life

9 years

Investments and Other [Member]

Goodwill [Roll Forward]

Balance as of December 31, 2014

$ 2.9

Acquired Goodwill

127.1

Balance as of March 31, 2015

$ 130.0

[1]	Developed Technology and Other includes patents, non-compete agreements, and land easements.

Derivatives - Hedged Item (Details) - Term Loan [Member] $ in Millions	Mar. 31, 2015 USD ($)
Debt Instrument [Line Items]
Term Loan Principal Amount	$ 75.0
Percentage of Debt Hedged by Interest Rate Derivatives	5.00%

Derivatives - Derivative (Details) - Interest Rate Swap [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative, Variable Interest Rate	one-month LIBOR
Interest Rate Swap Fixed Interest Rate	0.75%
Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	Cash flows from the Swap are expected to be highly effective. If it is determined that the Swap ceases to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessment of hedge effectiveness resulted in no ineffectiveness recorded for the three months ended March 31, 2015.
Interest Rate Swap Liability	$ 0.2	$ 0.3

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

3 Months Ended

12 Months Ended

Mar. 31, 2015

Dec. 31, 2014

Mar. 31, 2015

Dec. 31, 2014

Investments [Abstract]

Cash Equivalents

$ 2.8

$ 2.9

Recurring Fair Value Measurements [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

8.3

^[1]

8.1

^[2]

Available-for-sale - Corporate Debt Securities

11.0

^[1]

10.8

^[2]

Cash Equivalents

2.8

^[1]

2.9

^[2]

Total Fair Value of Assets

22.1

21.8

Liabilities [Abstract]

Deferred Compensation

15.4

^[3]

16.2

^[4]

Derivatives - Interest Rate Swap

0.2

^[5]

0.3

^[6]

U.S. Water Services Contingent Consideration

^[3]

$ 35.8

35.8

Total Fair Value of Liabilities

51.4

16.5

Total Net Fair Value of Assets (Liabilities)

(29.3)

5.3

Activity in Level 3 [Roll Forward]

Balance at March 31, 2015 and December 31, 2014

^[3]

35.8

Fair Value Hierarchy Transfers, All Levels

0.0

$ 0.0

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

Investments [Abstract]

Available-for-sale - Equity Securities

8.3

^[1]

8.1

^[2]

Available-for-sale - Corporate Debt Securities

0.0

^[1]

0.0

^[2]

Cash Equivalents

2.8

^[1]

2.9

^[2]

Total Fair Value of Assets

11.1

11.0

Liabilities [Abstract]

Deferred Compensation

0.0

^[3]

0.0

^[4]

Derivatives - Interest Rate Swap

0.0

^[5]

0.0

^[6]

U.S. Water Services Contingent Consideration

^[3]

0.0

Total Fair Value of Liabilities

0.0

Total Net Fair Value of Assets (Liabilities)

11.1

11.0

Activity in Level 3 [Roll Forward]

Balance at March 31, 2015 and December 31, 2014

^[3]

0.0

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

Investments [Abstract]

Available-for-sale - Equity Securities

0.0

^[1]

0.0

^[2]

Available-for-sale - Corporate Debt Securities

11.0

^[1]

10.8

^[2]

Cash Equivalents

0.0

^[1]

0.0

^[2]

Total Fair Value of Assets

11.0

10.8

Liabilities [Abstract]

Deferred Compensation

15.4

^[3]

16.2

^[4]

Derivatives - Interest Rate Swap

0.2

^[5]

0.3

^[6]

U.S. Water Services Contingent Consideration

^[3]

0.0

Total Fair Value of Liabilities

15.6

16.5

Total Net Fair Value of Assets (Liabilities)

(4.6)

(5.7)

Activity in Level 3 [Roll Forward]

Balance at March 31, 2015 and December 31, 2014

^[3]

0.0

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

Investments [Abstract]

Available-for-sale - Equity Securities

0.0

^[1]

0.0

^[2]

Available-for-sale - Corporate Debt Securities

0.0

^[1]

0.0

^[2]

Cash Equivalents

0.0

^[1]

0.0

^[2]

Total Fair Value of Assets

0.0

Liabilities [Abstract]

Deferred Compensation

0.0

^[3]

0.0

^[4]

Derivatives - Interest Rate Swap

0.0

^[5]

0.0

^[6]

U.S. Water Services Contingent Consideration

0.0

35.8

^[3]

0.0

Total Fair Value of Liabilities

35.8

0.0

Total Net Fair Value of Assets (Liabilities)

$ (35.8)

$ 0.0

Activity in Level 3 [Roll Forward]

Balance at March 31, 2015 and December 31, 2014

0.0

Activity in Level 3, Period Increase

0.0

Balance at March 31, 2015 and December 31, 2014

35.8

^[3]

$ 0.0

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

Activity in Level 3 [Roll Forward]

Activity in Level 3, Period Increase

35.7

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

Activity in Level 3 [Roll Forward]

Activity in Level 3, Period Increase

$ 0.1

[1]	Included in Other Investments on the Consolidated Balance Sheet.
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[5]	Included in Current Liabilities - Other on the Consolidated Balance Sheet.
[6]	Included in Current Liabilities - Other on the Consolidated Balance Sheet.

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2015	Dec. 31, 2014
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,376.1	$ 1,373.5
Long-Term Debt, Including Current Portion - Fair Value	$ 1,525.4	$ 1,484.5

Fair Value - Nonrecurring Fair Value Measures (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Nonrecurring Fair Value Measures [Abstract]
Equity Method Investment, Ownership Percentage	8.00%
Equity Method Investment, Carrying Amount	$ 122.3	$ 121.1
Intangible Assets, Carrying Amount	84.3	1.9
Fair Value, Measurements, Nonrecurring [Member]
Nonrecurring Fair Value Measures [Abstract]
Equity Method Investment, Carrying Amount	122.3	121.1
Equity Method Investment, Impairment	0.0	0.0
Goodwill, Carrying Amount	130.0	2.9
Goodwill, Impairment	0.0
Intangible Assets, Carrying Amount	84.3	1.9
Intangible Assets, Impairment	0.0
Property, Plant and Equipment, Impairment	$ 0.0	$ 0.0

Regulatory Matters - Utility Rates (Details)	Jan. 01, 2013	Jun. 01, 2011	Mar. 31, 2015 Customers Years MW
Bison Wind Energy Center [Member]
Public Utilities, General Disclosures [Line Items]
Generating Capacity (MW) \| MW			497
MPUC 2010 Minnesota Rate Case [Member] \| Electric Rates [Member] \| Retail Customers [Member]
Public Utilities, General Disclosures [Line Items]
Approved Rate of Return on Common Equity		10.38%
Approved Percentage of Capital Structure Related to Equity		54.29%
FERC-Approved Wholesale Rates [Member] \| Electric Rates [Member] \| Municipal Customers [Member]
Public Utilities, General Disclosures [Line Items]
Number of Customers \| Customers			16
Length of Notice Required to Terminate (Years) \| Years			3
PSCW 2012 Wisconsin Rate Case [Member] \| Retail Customers [Member]
Public Utilities, General Disclosures [Line Items]
Approved Rate of Return on Common Equity	10.90%

Regulatory Matters - Boswell Mercury Emissions Reduction Plan (Details) - Boswell Unit 4 [Member] $ in Millions	Mar. 31, 2015 USD ($)
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 260
Capital Cost Spent to Date	$ 162

Regulatory Matters - Great Northern Transmission Line (GNTL) (Details) - Great Northern Transmission Line [Member]	Mar. 31, 2015 kV Miles
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500

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

3 Months Ended

Mar. 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 Assets

$ 15.6

$ 16.3

Non-Current Regulatory Assets

358.0

357.3

Total Regulatory Assets

373.6

Non-Current Regulatory Liabilities

101.2

94.2

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

13.5

13.4

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

22.0

22.8

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

46.9

42.9

Deferred Fuel [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Assets

^[1]

15.6

16.3

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[2]

220.0

223.9

Non-Current Regulatory Liabilities

^[2]

2.9

3.5

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

46.8

46.6

Asset Retirement Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

18.6

17.8

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

^[3]

63.4

59.7

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

5.0

Other

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

4.2

4.3

Non-Current Regulatory Liabilities

$ 15.9

$ 11.6

[1]	Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
[2]	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. (See Note 15. Pension and Other Postretirement Benefit Plans.)
[3]	The cost recovery rider regulatory assets are due to capital expenditures related to our 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.

Investment in ATC (Details) - USD ($) $ in Millions		3 Months Ended
Investment in ATC (Details) - USD ($) $ in Millions	Apr. 30, 2015	Mar. 31, 2015	Mar. 31, 2014
Investment in ATC [Abstract]
Ownership Percentage		8.00%
Approved Return on Common Equity		12.20%
Equity Method Investment, Expected Additional Investment		$ 1.1
Subsequent Event [Line Items]
Cash Investments		0.4
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2014		121.1
Cash Investments		0.4
Equity Earnings in ATC		3.9	$ 5.1
Distributed ATC Earnings		(3.1)
Equity Investment Balance as of March 31, 2015		122.3
ATC Summarized Financial Data [Abstract]
Revenue		152.4	163.3
Operating Expense		80.0	78.6
Other Expense		24.4	21.6
Net Income		48.0	63.1
ALLETE's Equity in Net Income		$ 3.9	$ 5.1
Subsequent Event [Member]
Subsequent Event [Line Items]
Cash Investments	$ 0.4
ALLETE's Investment in ATC [Roll Forward]
Cash Investments	$ 0.4

Investment in ATC - FERC Complaints (Details) $ in Millions	3 Months Ended
Investment in ATC - FERC Complaints (Details) $ in Millions	Mar. 31, 2015 USD ($)
Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Basis Point Reduction on Approved Rate of Return on Common Equity	50
FERC Complaint 1 [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Proposed Return on Common Equity	9.15%
FERC Complaint 2 [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Proposed Return on Common Equity	8.67%
Rainy River Energy [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 1.4
Rainy River Energy [Member] \| FERC Complaint 2 [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	1.1
After-tax [Member] \| Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Effect on Future Earnings, Amount	0.5
Pre-tax [Member] \| Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Effect on Future Earnings, Amount	$ 0.9

Short-Term and Long-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Short-Term Debt Outstanding	$ 122.6		$ 104.4
Proceeds from Issuance of Long-Term Debt	0.0	$ 100.0
Long-Term Debt Outstanding	$ 1,253.8		$ 1,272.8

Short-Term and Long-Term Debt - Financial Covenants (Details)	Mar. 31, 2015
Financial Covenants [Abstract]
Required Indebtedness to Total Capital Ratio	0.65
Actual Indebtedness to Total Capital Ratio	0.44

Other Income (Expense) (Details) - USD ($) $ in Millions	3 Months Ended
Other Income (Expense) (Details) - USD ($) $ in Millions	Mar. 31, 2015	Mar. 31, 2014
Other Income (Expense) [Abstract]
AFUDC–Equity	$ 0.9	$ 1.8
Investments and Other Income	0.2	0.2
Total Other Income	$ 1.1	$ 2.0

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

3 Months Ended

Mar. 31, 2015

Mar. 31, 2014

Dec. 31, 2014

Current Tax Expense (Benefit) [Abstract]

Federal

^[1]

$ 0.0

State

^[1]

0.1

0.0

Total Current Tax Expense

0.1

0.0

Deferred Tax Expense (Benefit) [Abstract]

Federal

4.8

6.3

State

1.5

2.7

Investment Tax Credit Amortization

(0.2)

Total Deferred Tax Expense

6.1

8.8

Total Income Tax Expense

$ 6.2

$ 8.8

Effective Income Tax Rate

13.40%

20.70%

Federal Statutory Income Tax Rate

41.00%

Uncertain Tax Positions [Abstract]

Gross Unrecognized Tax Benefits

$ 2.0

Unrecognized Tax Benefits that Would Favorably Impact Effective Tax Rate

$ 0.3

[1]

For the three months ended March 31, 2015 and 2014, the federal and state current tax expense was minimal due to the utilization of NOL carryforwards from prior periods. The NOL carryforwards resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

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

3 Months Ended

Mar. 31, 2015

Mar. 31, 2014

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Loss

$ (21.1)

$ (17.1)

Other Comprehensive Income Before Reclassifications

0.3

0.0

Amounts Reclassified From Accumulated Other Comprehensive Loss

0.2

0.3

Net Other Comprehensive Income

0.5

0.3

Ending Accumulated Other Comprehensive Loss

(20.6)

(16.8)

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

AOCI Reclassification, Unrealized Gains on Available-for-sale Securities, Before Tax

0.0

AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items, Before Tax

(0.5)

Income Tax Expense [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

AOCI Reclassification, Unrealized Gains on Available-for-sale Securities, Tax

^[1]

0.1

0.0

AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items, Tax

^[1]

0.2

Operating Expenses - Operating and Maintenance [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items, Prior Service Costs, Before Tax

^[2]

0.1

AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items, Actuarial Gains and Losses, Before Tax

^[2]

(0.6)

Unrealized Gains and Losses on Available-for-sale Securities [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Loss

(0.3)

(0.1)

Other Comprehensive Income Before Reclassifications

0.2

0.0

Amounts Reclassified From Accumulated Other Comprehensive Loss

(0.1)

0.0

Net Other Comprehensive Income

0.1

0.0

Ending Accumulated Other Comprehensive Loss

(0.2)

(0.1)

Defined Benefit Pension and Other Postretirement Items [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Loss

(20.7)

(16.7)

Other Comprehensive Income Before Reclassifications

0.0

Amounts Reclassified From Accumulated Other Comprehensive Loss

0.3

Net Other Comprehensive Income

0.3

Ending Accumulated Other Comprehensive Loss

(20.4)

(16.4)

Gains and Losses on Cash Flow Hedge [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Loss

(0.1)

(0.3)

Other Comprehensive Income Before Reclassifications

0.1

0.0

Amounts Reclassified From Accumulated Other Comprehensive Loss

0.0

Net Other Comprehensive Income

0.1

0.0

Ending Accumulated Other Comprehensive Loss

$ 0.0

$ (0.3)

[1]	Included in Income Tax Expense on our Consolidated Statement of Income.
[2]	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 15. Pension and Other Postretirement Benefit Plans.)

Earnings Per Share and Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions					3 Months Ended
	Feb. 04, 2015	Sep. 05, 2014	Mar. 04, 2014	Feb. 26, 2014	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share and Common Stock [Abstract]
Antidilutive Shares Excluded from Diluted EPS Computation					0.0	0.0
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE					$ 39.9	$ 33.5
Average Common Shares					46.9	41.4
Earnings Per Share					$ 0.85	$ 0.81
Earnings Per Share - Diluted [Abstract]
Net Income to Attributable ALLETE					$ 39.9	$ 33.5
Average Common Shares					47.1	41.6
Earnings Per Share					$ 0.85	$ 0.80
Dilutive Securities (in shares)					0.2	0.2
Proceeds from Issuance of Common Stock - Pension Plan					$ 0.0	$ 19.5
Common Stock Issued - Pension Plan (in shares)						0.4
Forward Contracts [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Indexed Shares				2.8
Common Stock Issued - Option Agreement (in shares)	1.4	1.4
Proceeds from Issuance of Common Stock - Option Agreement	$ 65.4	$ 65.0
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share				$ 48.01
Options Held [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Common Stock Issued - Option Agreement (in shares)			0.4
Proceeds from Issuance of Common Stock - Option Agreement			$ 20.2

Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Pension [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	$ 2.5	$ 2.1
Interest Cost	7.5	7.4
Expected Return on Plan Assets	(10.2)	(9.6)
Amortization of Prior Service Costs (Credits)	0.0	0.1
Amortization of Net Loss	4.5	3.6
Net Periodic Benefit Expense (Income)	4.3	3.6
Contributions	0.0	19.5
Estimated Future Contributions	0.0
Other Postretirement [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	1.1	0.9
Interest Cost	1.8	1.8
Expected Return on Plan Assets	(2.7)	(2.6)
Amortization of Prior Service Costs (Credits)	(0.8)	(0.6)
Amortization of Net Loss	0.1	0.1
Net Periodic Benefit Expense (Income)	(0.5)	(0.4)
Contributions	0.0	$ 0.0
Estimated Future Contributions	$ 0.0

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details)	3 Months Ended		7 Months Ended
	Mar. 31, 2015 USD ($) Years MWh MW	Mar. 31, 2014 USD ($)	Dec. 31, 2014
Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Debt Outstanding \| $	$ 390,900,000
Annual Debt Service \| $	45,000,000
Power Purchased under Long-term Contracts \| $	19,200,000	$ 16,800,000
Interest Expense \| $	$ 2,500,000	$ 2,500,000
Square Butte PPA [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)	455
Output Entitlement	50.00%
Square Butte PPA [Member] \| Minnkota Sales Agreement [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Output Entitlement	28.00%		23.00%
Minnkota PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Oliver Wind I PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Fixed Capacity Charges \| $	$ 0
Oliver Wind II PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Fixed Capacity Charges \| $	$ 0
Manitoba Hydro PPA (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro PPA (expires April 2022) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh) \| MWh	1,000,000
Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Term of Contract (Years) \| Years	15
Manitoba Hydro PPA (expires 2040) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	133
Term of Contract (Years) \| Years	20
Great River Energy PPA (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Great River Energy Capacity Only PPA (expires May 2020) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) - Coal Supply and Transportation [Member] $ in Millions	Mar. 31, 2015 USD ($)
Coal, Rail and Shipping Contracts [Line Items]
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation for Remainder of 2015	$ 42.3
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2016	27.0
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2017	27.6
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2018	$ 28.4

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) $ in Millions	Mar. 31, 2015 USD ($)
Leasing Agreements [Line Items]
Operating Leases, Minimum Payments Due in 2015	$ 13.4
Operating Leases, Minimum Payments Due in 2016	11.4
Operating Leases, Minimum Payments Due in 2017	10.6
Operating Leases, Minimum Payments Due in 2018	9.5
Operating Leases, Minimum Payments Due in 2019	8.3
Operating Leases, Minimum Payments Due Thereafter	27.3
BNI Coal Dragline Lease [Member]
Leasing Agreements [Line Items]
Operating Leases, Minimum Payments Due in 2015	2.8
Termination Fee	3.0
Operating Leases, Minimum Payments Due in 2016	2.8
Operating Leases, Minimum Payments Due in 2017	2.8
Operating Leases, Minimum Payments Due in 2018	2.8
Operating Leases, Minimum Payments Due in 2019	2.8
Operating Leases, Minimum Payments Due Thereafter	$ 22.4

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	Mar. 31, 2015 USD ($) kV Miles
CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	3
Estimated Capital Expenditures	$ 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]
Estimated Capital Expenditures	$ 560
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	$ 710
Completed Projects - Current Year [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	1
Completed Projects - Prior Years [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	2

Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	3 Months Ended
	Mar. 31, 2015 USD ($) MW
Boswell Unit 4 [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures	$ 260
Capital Cost Spent to Date	162
Maximum [Member] \| Clean Water Act - Aquatic Organisms [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	15
Maximum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	$ 130
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Generating Unit 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	3 Months Ended
	Mar. 31, 2015 USD ($) Years	Dec. 31, 2014
U.S. Water Services [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 3.2
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	49.3
BNI Coal Reclamation Liability [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.6
BNI Coal Reclamation Liability [Member] \| Surety Bonds [Member]
Guarantor Obligations [Line Items]
Collateral	49.5
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	7.1
ALLETE Properties Development and Maintenance Obligations [Member] \| Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	10.2
Town Center Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Bond Original Principal	$ 26.4
Bond Interest Rate	6.00%
Bond Term (in Years) \| Years	31
Ownership Percentage of Benefited Property	72.00%	72.00%
Annual Assessment	$ 1.4
Palm Coast Park Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Bond Original Principal	$ 31.8
Bond Interest Rate	5.70%
Bond Term (in Years) \| Years	31
Ownership Percentage of Benefited Property	93.00%	93.00%
Annual Assessment	$ 2.1