Document and Entity Information Document (USD $)	3 Months Ended
Document and Entity Information Document (USD $)	Mar. 31, 2014	Jun. 30, 2013
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		$ 1,989,608,714
Entity Common Stock, Shares Outstanding	42,357,546
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current Assets [Abstract]
Cash and Cash Equivalents	$ 44.6	$ 97.3
Accounts Receivable (Less Allowance of $1.0 and $1.1)	97.4	96.3
Inventories	68.9	59.3
Prepayments and Other	33.4	35.1
Deferred Income Taxes	25.1	19.0
Total Current Assets	269.4	307.0
Property, Plant and Equipment - Net	2,905.1	2,576.5
Regulatory Assets	267.0	263.8
Investment in ATC	116.6	114.6
Other Investments	116.4	146.3
Other Non-Current Assets	74.7	68.6
Total Assets	3,749.2	3,476.8
Current Liabilities [Abstract]
Accounts Payable	78.1	99.9
Accrued Taxes	42.9	34.8
Accrued Interest	15.2	15.7
Long-Term Debt Due Within One Year	11.1	27.2
Other	61.2	52.6
Total Current Liabilities	208.5	230.2
Long-Term Debt	1,202.5	1,083.0
Deferred Income Taxes	494.4	479.1
Regulatory Liabilities	89.9	81.0
Defined Benefit Pension and Other Postretirement Benefit Plans	117.2	133.4
Other Non-Current Liabilities	229.3	127.2
Total Liabilities	2,341.8	2,133.9
Commitments, Guarantees and Contingencies (Note 15)
Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 42.2 and 41.4 Shares Outstanding	930.4	885.2
Unearned ESOP Shares	(12.5)	(14.3)
Accumulated Other Comprehensive Loss	(16.8)	(17.1)
Retained Earnings	501.4	489.1
Total ALLETE Equity	1,402.5	1,342.9
Non-Controlling Interest in Subsidiaries	4.9	0
Total Equity	1,407.4	1,342.9
Total Liabilities and Equity	$ 3,749.2	$ 3,476.8

Consolidated Balance Sheet Parentheticals (USD $) In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.0	$ 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	42.4	41.4

Consolidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Revenue	$ 296.5	$ 263.8
Operating Expenses [Abstract]
Fuel and Purchased Power	96.2	86.5
Operating and Maintenance	119.8	104.7
Depreciation	32.2	28.2
Total Operating Expenses	248.2	219.4
Operating Income	48.3	44.4
Other Income (Expense) [Abstract]
Interest Expense	(12.8)	(12.3)
Equity Earnings in ATC	5.1	5.2
Other	2.0	2.7
Total Other Expense	(5.7)	(4.4)
Income Before Non-Controlling Interest and Income Taxes	42.6	40.0
Income Tax Expense	8.8	7.5
Net Income	33.8	32.5
Less: Non-Controlling Interest in Subsidiaries	0.3	0
Net Income Attributable to ALLETE	$ 33.5	$ 32.5
Average Shares of Common Stock [Abstract]
Basic	41.4	38.9
Diluted	41.6	39.0
Basic Earnings Per Share of Common Stock	$ 0.81	$ 0.83
Diluted Earnings Per Share of Common Stock	$ 0.80	$ 0.83
Dividends Per Share of Common Stock	$ 0.49	$ 0.475

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Comprehensive Income [Abstract]
Net Income	$ 33.8	$ 32.5
Other Comprehensive Income [Abstract]
Unrealized Gain on Derivatives, Net of Income Taxes of $0.1 and $-	0	0.1
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	0.3	0.4
Total Comprehensive Income	34.1	32.9
Less: Non-Controlling Interest in Subsidiaries	0.3	0
Comprehensive Income Attributable to ALLETE	$ 33.8	$ 32.9

- Definition

Amount after tax of increase (decrease) in accumulated gain (loss) from derivative instruments designated and qualifying as the effective portion of cash flow hedges and an entity's share of an equity investee's increase (decrease) in deferred hedging gain (loss).

+ References+ Details

Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain on Derivatives, Tax	$ 0.1	$ 0
Defined Benefit Pension and Other Postretirement Benefit Plans, Tax	$ 0.2	$ 0.2

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Activities [Abstract]
Net Income	$ 33.8	$ 32.5
Allowance for Funds Used During Construction - Equity	(1.8)	(1.1)
Income from Equity Investments, Net of Dividends	(0.8)	(1.3)
Gain on Sale of Assets / Investments	0	(1.0)
Depreciation Expense	32.2	28.2
Amortization of Debt Issuance Costs	0.3	0.3
Deferred Income Tax Expense	8.8	7.3
Share-Based Compensation Expense	0.8	0.6
ESOP Compensation Expense	2.2	2.0
Defined Benefit Pension and Postretirement Benefit Expense	3.2	5.6
Bad Debt Expense	0.2	0.1
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	2.9	2.7
Inventories	(6.5)	5.5
Prepayments and Other	2.2	5.5
Accounts Payable	0.1	(11.0)
Other Current Liabilities	1.6	(0.7)
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans	0	(10.8)
Changes in Regulatory and Other Non-Current Assets	(4.0)	(1.9)
Changes in Regulatory and Other Non-Current Liabilities	(0.3)	(4.3)
Cash from Operating Activities	74.9	58.2
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	0.6	7.9
Payments for Purchase of Available-for-sale Securities	(0.7)	(1.2)
Investment in ATC	(1.2)	(0.4)
Changes to Other Investments	30.0	(1.0)
Additions to Property, Plant and Equipment	(216.2)	(69.8)
Acquisition – Net of Cash Acquired	(23.1)	0
Changes in Restricted Cash	6.0	0
Proceeds from Sale of Assets	0	0.6
Cash for Investing Activities	(204.6)	(63.9)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	24.8	23.4
Proceeds from Issuance of Long-Term Debt	100.0	0
Reductions of Long-Term Debt	(19.8)	(1.7)
Debt Issuance Costs	(0.9)	0
Acquisition of Non-Controlling Interest	(6.0)	0
Dividends on Common Stock	(21.1)	(19.5)
Cash from Financing Activities	77.0	2.2
Change in Cash and Cash Equivalents	(52.7)	(3.5)
Cash and Cash Equivalents at Beginning of Period	97.3	80.8
Cash and Cash Equivalents at End of Period	$ 44.6	$ 77.3

Operations and Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

Operations and Significant Accounting Policies [Abstract]

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

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.



Inventories	March 31, 2014		December 31, 2013
Millions
Fuel		$16.3		$13.1
Materials and Supplies	52.6		46.2
Total Inventories		$68.9		$59.3



Prepayments and Other Current Assets	March 31, 2014		December 31, 2013
Millions
Deferred Fuel Adjustment Clause		$22.1		$23.0
Other	11.3		12.1
Total Prepayments and Other Current Assets		$33.4		$35.1

Other Non-Current Assets. As of March 31, 2014, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $5.3 million related to ALLETE Clean Energy’s wind energy facilities acquisition, which was completed on January 30, 2014 (see Note 4. Acquisitions). As of December 31, 2013, restricted cash of $5.4 million related to cash held in escrow pending the closing of the acquisition.



Other Current Liabilities	March 31, 2014		December 31, 2013
Millions
Customer Deposits		$24.1		$26.0
Power Purchase Agreements (a)	13.1		—
Other	24.0		26.6
Total Other Current Liabilities		$61.2		$52.6


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisitions).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Non-Current Liabilities	March 31, 2014		December 31, 2013
Millions
Asset Retirement Obligation		$89.2		$81.8
Power Purchase Agreements (a)	96.4		—
Other	43.7		45.4
Total Other Non-Current Liabilities		$229.3		$127.2


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisitions).

Supplemental Statement of Cash Flows Information.



For the Three Months Ended March 31,	2014		2013
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$12.4		$12.0
Cash Paid During the Period for Income Taxes		$0.2		$0.5
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(22.6)		$(26.2)
Capitalized Asset Retirement Costs		$0.6		$1.9
AFUDC – Equity		$1.8		$1.1
ALLETE Common Stock Contributed to the Pension Plan		$19.5	—

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

New Accounting Standards.

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, the FASB issued an accounting standard update on the financial statement presentation of unrecognized tax benefits when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward. To the extent an NOL carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from the disallowance of a tax position or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This guidance was adopted beginning with the quarter ending March 31, 2014, and did not have a material impact on our consolidated financial position, results of operations, or cash flows.

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 will be effective beginning with the quarter ending March 31, 2015, and applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

Business Segments

3 Months Ended

Mar. 31, 2014

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 BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business which acquired three wind energy facilities in January 2014, and is aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes 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.



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2014
Operating Revenue		$296.5			$264.2			$32.3
Fuel and Purchased Power Expense	96.2			96.2			—
Operating and Maintenance Expense	119.8			90.2			29.6
Depreciation Expense	32.2			28.8			3.4
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

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2013
Operating Revenue		$263.8			$241.4			$22.4
Fuel and Purchased Power Expense	86.5			86.5			—
Operating and Maintenance Expense	104.7			82.2			22.5
Depreciation Expense	28.2			26.8			1.4
Operating Income (Loss)	44.4			45.9			(1.5		)
Interest Expense	(12.3		)	(10.7		)	(1.6		)
Equity Earnings in ATC	5.2			5.2			—
Other Income	2.7			1.1			1.6
Income (Loss) Before Non-Controlling Interest and Income Taxes	40.0			41.5			(1.5		)
Income Tax Expense (Benefit)	7.5			9.4			(1.9		)
Net Income	32.5			32.1			0.4
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$32.5			$32.1			$0.4

As of March 31, 2013
Total Assets		$3,251.3			$2,967.9			$283.4
Property, Plant and Equipment – Net		$2,366.7			$2,300.8			$65.9
Accumulated Depreciation		$1,179.8			$1,121.8			$58.0
Capital Additions		$43.1			$42.6			$0.5

- 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.

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+ Details

Investments

3 Months Ended

Mar. 31, 2014

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At March 31, 2014, our long-term 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, 2014		December 31, 2013
Millions
ALLETE Properties		$90.1		$89.9
Available-for-sale Securities (a)	19.8		17.7
Cash Equivalents (b)	3.9		34.2
Other	2.6		4.5
Total Other Investments		$116.4		$146.3


(a)	As of March 31, 2014, 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 $4.0 million, in three years to less than five years was $1.3 million, and in five or more years was $4.3 million.


(b)	During the quarter ended March 31, 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.

NOTE 3. INVESTMENTS (Continued)



ALLETE Properties	March 31, 2014		December 31, 2013
Millions
Land Inventory Beginning Balance		$85.4		$86.5
Cost of Sales	—		(1.5		)
Other	0.2		0.4
Land Inventory Ending Balance	85.6		85.4
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4		1.4
Other	3.1		3.1
Total Real Estate Assets		$90.1		$89.9

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 impairment on a quarterly basis and no impairments were recorded for the quarter ended March 31, 2014 (none for the year ended December 31, 2013).

Long-Term Finance Receivables. As of March 31, 2014, long-term finance receivables were $1.4 million net of allowance ($1.4 million net of allowance as of December 31, 2013). 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, 2014, we had an allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2013).

Acquisitions

3 Months Ended

Mar. 31, 2014

Acquisitions [Abstract]

Business Combination Disclosure [Text Block]

ACQUISITIONS

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake) and Condon, Oregon (Condon) from The AES Corporation (AES) for $26.9 million, subject to a working capital adjustment. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015. The acquisition supports ALLETE’s strategy to pursue energy-centric initiatives through ALLETE Clean Energy that include less carbon intensive and more sustainable energy sources.

Lake Benton, Storm Lake and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake 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 (see Note 15. Commitments, Guarantees and Contingencies). Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility in June 2015. Armenia Mountain began operations in 2009.

ALLETE Clean Energy acquired a controlling interest in the limited liability company (LLC) which owns Lake Benton and Storm Lake, 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 preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as shown in the table below. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to property, plant and equipment, PPAs and non-controlling interest; subsequent adjustments could impact the amount of goodwill recorded or result in a bargain purchase. Fair value measurements were valued primarily using the discounted cash flow method.

NOTE 4. ACQUISITIONS (Continued)



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	12.4
Property, Plant and Equipment – Net	161.2
Other Non-Current Assets (a)	8.1
Total Assets Acquired		$185.5
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	10.1
Non-Controlling Interest (c)	10.6
Total Liabilities and Non-Controlling Interest Assumed	158.6
Net Identifiable Assets Acquired		$26.9


(a)	Included in Other Non-Current Assets was the fair value estimate of $0.3 million for the option to purchase Armenia Mountain in 2015, and preliminary goodwill of $1.9 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 preliminary purchase price accounting valued the non-controlling interest of Lake Benton, Storm Lake and Condon at fair value primarily on the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm lake was subsequently purchased by ALLETE Clean Energy.

ALLETE Clean Energy incurred $1.4 million after-tax of acquisition-related costs during the quarter ended March 31, 2014, which were expensed when incurred and were recorded in Other Expenses on the Consolidated Statement of Income. The results of operations of this business from its acquisition date are included in the Investments and Other segment. The pro forma impact of this acquisition was not significant to the results of the Company for the three months ended March 31, 2014 or March 31, 2013.

On February 11, 2014, ALLETE Clean Energy purchased the non-controlling interest related to Lake Benton and Storm Lake 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.

- 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

Derivatives	3 Months Ended
Derivatives	Mar. 31, 2014
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES We have two variable-to-fixed interest rate swaps (Swaps), designated as cash flow hedges, in order to manage the interest rate risk associated with a $75.0 million Term Loan which represents approximately 6 percent of the Company’s outstanding long-term debt as of March 31, 2014. (See Note 9. Short-Term and Long-Term Debt.) The Swaps have effective dates of August 25, 2011, and August 26, 2014, and mature on August 25, 2014 and 2015, respectively. The Swaps involve the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreements at 0.825 percent and 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swaps are expected to be highly effective. If it is determined the Swaps cease 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 assessments of hedge effectiveness resulted in no ineffectiveness recorded for the quarter ended March 31, 2014. As of March 31, 2014, the fair value of the Swaps was a $0.5 million liability ($0.6 million liability as of December 31, 2013) of which $0.3 million ($0.3 million as of December 31, 2013) was included in Other Non-Current Liabilities and $0.2 million ($0.3 million as of December 31, 2013) was included in Other Current Liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swaps were recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income (Loss) related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions 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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Fair Value

3 Months Ended

Mar. 31, 2014

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 2013 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, 2014, and December 31, 2013. 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 and 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.



	Fair Value as of March 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$9.8	—		—		$9.8
Available-for-sale – Corporate Debt Securities	—			$10.0	—	10.0
Cash Equivalents	3.9		—		—	3.9
Total Fair Value of Assets		$13.7		$10.0	—		$23.7

Liabilities:
Deferred Compensation (b)	—			$18.7	—		$18.7
Derivatives – Interest Rate Swap (c)	—		0.5		—	0.5
Total Fair Value of Liabilities	—			$19.2	—		$19.2
Total Net Fair Value of Assets (Liabilities)		$13.7	$(9.2)		—		$4.5


(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 and Other Non-Current Liabilities on the Consolidated Balance Sheet.

NOTE 6. FAIR VALUE (Continued)



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.9	—		—		$7.9
Available-for-sale – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9

Liabilities:
Deferred Compensation (b)	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap (c)	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5


(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 and Other Non-Current Liabilities on the Consolidated Balance Sheet.

There was no activity in Level 3 during the quarters ended March 31, 2014 and 2013.

The Company’s policy is to recognize transfers in and transfers out of a given level as of the actual date of the event or of the change in circumstances that caused the transfer. For the quarters ended March 31, 2014 and 2013, 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, 2014	$1,213.6	$1,282.9
December 31, 2013	$1,110.2	$1,131.7

- 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, 2014

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.

NOTE 7. REGULATORY MATTERS (Continued)

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota. SWL&P, a wholly-owned subsidiary of ALLETE, is a private utility in Wisconsin and also a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. 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 agreements 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 July 1, 2023. Under the agreements with the remaining 15 municipal customer 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. On November 12, 2013, 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. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates.

Renewable Cost Recovery Rider. The Bison Wind Energy Center in North Dakota currently consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in an order dated December 3, 2013. On September 25, 2013, the NDPSC approved the site permit for construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. As a result, construction has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $187.1 million was spent through March 31, 2014. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We included Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in a filing on April 29, 2014, which, upon approval, will authorize updated rates to be included on customer bills.

ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. In July 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

Integrated Resource Plan. In an order dated November 12, 2013, 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, installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to cleaner-burning natural gas in 2015 and retiring Taconite Harbor Unit 3 in 2015.

NOTE 7. REGULATORY MATTERS (Continued)

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. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. 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 $310 million. On November 5, 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. On November 25, 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. On December 20, 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which is expected to be approved in mid-2014.

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. On October 21, 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined that the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 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. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020. (See Note 15. Commitments, Guarantees and Contingencies.)

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities represent amounts expected to be refunded or credited to customers in rates. 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 commission or over the corresponding period related to the asset or liability.

NOTE 7. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	March 31, 2014		December 31, 2013
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.1		$23.0
Total Current Regulatory Assets	22.1		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	164.7		164.1
Income Taxes	36.2		35.3
Asset Retirement Obligations	16.7		16.0
Cost Recovery Riders (c)	40.3		39.6
PPACA Income Tax Deferral	5.0		5.0
Other	4.1		3.8
Total Non-Current Regulatory Assets	267.0		263.8
Total Regulatory Assets		$289.1		$286.8

Non-Current Regulatory Liabilities
Income Taxes		$17.1		$17.0
Plant Removal Obligations	20.4		19.7
Wholesale and Retail Contra AFUDC	23.7		19.7
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	15.9		16.3
Other	12.8		8.3
Total Non-Current Regulatory Liabilities		$89.9		$81.0


(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 14. Pension and Other Postretirement Benefit Plans).


(c)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC

3 Months Ended

Mar. 31, 2014

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 FERC-approved and are based on a 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, 2014, our equity investment in ATC was $116.6 million ($114.6 million at December 31, 2013). In the first three months of 2014, we invested $1.2 million in ATC, and on April 29, 2014, we invested an additional $1.2 million. We expect to make additional investments of approximately $3.4 million in 2014.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2013		$114.6
Cash Investments	1.2
Equity in ATC Earnings	5.1
Distributed ATC Earnings	(4.3		)
Equity Investment Balance as of March 31, 2014		$116.6

NOTE 8. INVESTMENT IN ATC (Continued)

ATC’s summarized financial data for the quarters ended March 31, 2014 and 2013, is as follows:



	Quarter Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2014		2013
Millions
Revenue		$163.3	$151.8
Operating Expense	78.6		69.8
Other Expense	21.6		21.5
Net Income		$63.1	$60.5
ALLETE’s Equity in Net Income		$5.1	$5.2

- Definition

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

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Short-Term and Long-Term Debt

3 Months Ended

Mar. 31, 2014

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, 2014, total short-term debt outstanding was $11.1 million ($27.2 million as of December 31, 2013) and consisted of long-term debt due within one year. Short-term debt as of December 31, 2013, included $18.0 million of long-term debt that matured in January 2014.

Long-Term Debt. As of March 31, 2014, total long-term debt outstanding was $1,202.5 million ($1,083.0 million as of December 31, 2013). In conjunction with ALLETE Clean Energy’s January 30, 2014 wind energy facilities acquisition, ALLETE Clean Energy assumed $23.3 million of long-term debt, including $2.2 million due within one year (see Note 4. Acquisitions).

In December 2013, we agreed to sell $215.0 million in 2014 of ALLETE first mortgage bonds (Bonds) in the private placement market in four series as described in the following table. On March 4, 2014, we issued $100.0 million of the Bonds. We expect to issue the remaining two series on, or about, June 26, 2014, as shown below:



Issue Date (on or about)	Maturity Date	Principal Amount	Interest Rate
March 4, 2014	March 15, 2024	$60 Million	3.69%
March 4, 2014	March 15, 2044	$40 Million	4.95%
June 26, 2014	July 15, 2022	$75 Million	3.40%
June 26, 2014	July 15, 2044	$40 Million	5.05%

The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company intends to use the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures or for general corporate purposes. The Bonds were and will be sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

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, 2014, our ratio was approximately 0.46 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from a 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, 2014, ALLETE was in compliance with its financial covenants.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

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Income Tax Expense

3 Months Ended

Mar. 31, 2014

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended
	March 31,
	2014			2013
Millions
Current Tax Expense (Benefit)
Federal (a)	—				$0.2
State (a)	—			—
Total Current Tax Expense (Benefit)	—			0.2
Deferred Tax Expense (Benefit)
Federal		$6.3			$5.8
State	2.7			1.7
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Tax Expense	8.8			7.3
Total Income Tax Expense		$8.8			$7.5

(a)

For the quarter ended March 31, 2014, the federal and state current tax expense of zero was due to the utilization of NOL carryforwards from prior periods. For the quarter ended March 31, 2013, the federal and state current tax expense of $0.2 million and zero, respectively, was due to federal and state NOLs which resulted from the bonus depreciation provision of the American Taxpayer Relief Act of 2012. The federal and state NOLs remaining after utilization in 2014 will be carried forward to offset future taxable income.

For the quarter ended March 31, 2014, the effective tax rate was 20.7 percent (18.8 percent for the quarter ended March 31, 2013). The increase from the effective tax rate for the quarter ended March 31, 2013, was primarily due to higher pretax income. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC–Equity, investment tax credits, renewable tax credits and depletion.

Uncertain Tax Positions. As of March 31, 2014, we had gross unrecognized tax benefits of $1.2 million ($1.2 million as of December 31, 2013). Of the total gross unrecognized tax benefits, $0.2 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 (see Note 1. Operations and Significant Accounting Policies).

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 2009, or state examination for years before 2005.

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. The regulations are generally effective for tax years beginning January 1, 2014. As ALLETE is adopting certain utility-specific guidance for deductible repairs previously issued by the IRS, the final regulation did not have a material impact on our consolidated financial statements.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

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Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2014

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 quarters ended March 31, 2014 and 2013, 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
For the Quarter 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 Income	—	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)

For the Quarter Ended March 31, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)	$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income (Loss) Before Reclassifications	0.5	(2.9)	0.1	(2.3)
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(0.5)	3.2	—	2.7
Net Other Comprehensive Income	—	0.3	0.1	0.4
Ending Accumulated Other Comprehensive Loss	$(0.1)	$(21.2)	$(0.3)	$(21.6)

Reclassifications from accumulated other comprehensive loss for the quarters ended March 31, 2014 and 2013, were as follows:



	Quarter Ended	Quarter Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	March 31,	March 31,
	2014	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	—	$0.8
Income Taxes (b)	—	(0.3)
Total, Net of Income Taxes	—	$0.5

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.1	$0.5
Actuarial Gains and Losses (c)	(0.6)	(5.7)
Total	(0.5)	(5.2)
Income Taxes (b)	0.2	2.0
Total, Net of Income Taxes	$(0.3)	$(3.2)
Total Reclassifications	$(0.3)	$(2.7)


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


(b)	Included in Income Tax Expense on the Consolidated Statement of Income.


(c)	Defined benefit pension and other postretirement benefit 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 14. 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, 2014

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 quarters ended March 31, 2014 and 2013, zero and 0.1 million options to purchase shares of common stock, respectively, were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.



			2014					2013
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
For the Quarter Ended March 31,
Net Income		$33.5			$33.5		$32.5			$32.5
Average Common Shares	41.4		0.2	41.6		38.9		0.1	39.0
Earnings Per Share		$0.81			$0.80		$0.83			$0.83

Forward Sale Agreement and Issuance of Common Stock. On February 26, 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. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with our capital investment strategy.

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock (borrowed shares) from third parties and sold them to the underwriters. ALLETE has right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elects physical settlement of the Agreement, it will deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price is initially $48.01 per share, subject to adjustment as provided in the Agreement. The Agreement provides for settlement at any time on or prior to March 1, 2015. ALLETE expect to physically settle the Agreement in its entirety by delivering 2.8 million shares of its common stock.

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 on March 4, 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.

The equity forward transaction was reflected in ALLETE’s diluted earnings per share using the treasury stock method, which resulted in no material dilutive impact to ALLETE’s diluted earnings per share for the quarter ended March 31, 2014. Prior to a settlement date, any dilutive effect of the Agreement on our earnings per share would only occur during periods when the average market price per share of our common stock is above the per share adjusted forward sales price described above.

The equity forward transaction has no initial fair value since it was entered into at the then market price of the common stock. ALLETE will not receive any proceeds with respect to the borrowed shares until the equity forward transaction is settled, and at that time the proceeds, if any, will be recorded in equity. The equity forward transaction is accounted for as an equity instrument in accordance with the accounting guidance for distinguishing liabilities from equity and the guidance for derivatives. Under the accounting guidance, the transaction qualifies for an exception from derivative accounting because the forward sale transaction is indexed to ALLETE’s stock.

Contributions to Pension. On January 10, 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 and had an aggregate value of $19.5 million when contributed.

- Definition

The entire disclosure for earnings per share.

+ References+ Details

Pension and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2014

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	2014			2013			2014			2013
Millions
For the Quarter Ended March 31,
Service Cost		$2.1			$2.5			$0.9			$1.0
Interest Cost	7.4			6.5			1.8			1.7
Expected Return on Plan Assets	(9.6		)	(8.8		)	(2.6		)	(2.5		)
Amortization of Prior Service Costs (Credits)	0.1			0.1			(0.6		)	(0.6		)
Amortization of Net Loss	3.6			5.3			0.1			0.4
Net Periodic Benefit Expense		$3.6			$5.6		$(0.4)			—

Employer Contributions. For the quarter ended March 31, 2014, $19.5 million of ALLETE common stock was contributed to our defined benefit pension plan (no contributions for the quarter ended March 31, 2013). For the quarter ended March 31, 2014, we made no contributions to our other postretirement benefit plan ($10.8 million for the quarter ended March 31, 2013). We do not expect to make any additional contributions to our defined benefit pension plan in 2014, and we do not expect to make any contributions to our other postretirement benefit plan in 2014.

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2014

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. At Minnesota Power, 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 contract, 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, 2014, Square Butte had total debt outstanding of $423.4 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the years 2014 through 2018, 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, 2014, was $16.8 million ($16.3 million for the three months ended March 31, 2013). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $2.5 million during the three months ended March 31, 2014 ($2.6 million for the three months ended March 31, 2013). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will sell 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.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

No power will be sold under the 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is expected to occur in mid-2014. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which in turn will enable Minnesota Power to transmit additional wind generation on the existing DC transmission line.

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 over the term 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. In 2006 and 2007, 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. Each agreement is for 25 years and 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 2015. 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.

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power 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. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices.

North Dakota Wind Development. Minnesota Power uses the 465-mile, 250 kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit.

Our 292 MW Bison Wind Energy Center, located in North Dakota, was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in an order dated December 3, 2013.

On September 25, 2013, the NDPSC approved the site permit for Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. As a result, construction has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $187.1 million was spent through March 31, 2014. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We included Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in a filing on April 29, 2014, which, upon approval, will authorize updated rates to be included on customer bills.

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly the Thomson Energy Center (Thomson), which had damage to the forebay canal and flooding at the facility. Minnesota Power worked closely with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs, to restore the Thomson facility and to rebuild the forebay embankment. Minnesota Power continues restoration and upgrade work at the Thomson facility and completed rebuilding the forebay embankment. Minnesota Power anticipates partial generation at the Thomson Energy Center in the second quarter of 2014. Work is ongoing toward returning to full generation late in 2014 and improving the spillway capacity at the Thomson dam in 2015. Total project costs are estimated to be approximately $90 million, of which $66.4 million was spent through March 31, 2014. A request seeking cost recovery of capital expenditures related to the restoration and repair of the Thomson facility through a renewable resources rider is expected to be filed with the MPUC in 2014.

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 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Currently, Minnesota Power is in discussions regarding the extension of our coal supply and transportation contracts beyond 2015. Our minimum annual payment obligation under these supply and transportation agreements is $26.0 million for the remainder of 2014 and $4.0 million for 2015. Our minimum annual payment obligation will increase when annual nominations are made for coal deliveries in future years. 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 2021. The aggregate amount of minimum lease payments for all operating leases is $12.1 million in 2014, $11.5 million in 2015, $9.5 million in 2016, $8.7 million in 2017, $7.4 million in 2018 and $29.2 million thereafter.

Transmission. We continue to make investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. This includes the CapX2020 initiative, investments in our own transmission assets, investments in other regional 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 November 2013, 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. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates.

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, 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. Studies show that the region’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, which is currently under construction and expected to be in service by 2015. The North Dakota permitting process was completed in August 2012.

Based on projected costs of the three transmission line projects and the allocation agreements among participating utilities, in total Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015, of which $85.7 million was spent through March 31, 2014. 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. Before a large energy facility can be sited or constructed in Minnesota, the MPUC requires a Certificate of Need, which was filed in October 2013. In an order dated January 8, 2014, 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 April 15, 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. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction 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 $500 million and $650 million, depending on the final route of the line. Minnesota Power will 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 become available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that Boswell Unit 4’s Title V permit was violated. In April 2011, Minnesota Power received a NOV 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 believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, retirements or refueling of generating units, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures, that may be required upon resolution. Any costs of retirements, refueling, or installing additional pollution control equipment 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 July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, in August 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit (Circuit Court of Appeals) vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. In March 2013, the EPA petitioned the Supreme Court to review the Circuit Court of Appeals ruling. In April 2014, the Supreme Court issued a decision reversing the Circuit Court of Appeals and upholding the CSAPR. The Supreme Court remanded the case to the Circuit Court of Appeals for further proceedings. We are reviewing the Supreme Court’s decision. The CSAPR would require states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR would not directly require the installation of controls. Instead, the rule would require facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would be allocated to facilities from each state’s annual budget and could be bought and sold.

The CAIR regulations similarly require certain states to improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CAIR also created an allowance allocation and trading program rather than specifying pollution controls. Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA completed a review of air quality modeling issues in conjunction with the development of a final replacement rule. While the CAIR remains in effect, Minnesota participation in the CAIR will continue to be stayed.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation, these emission reductions would have satisfied Minnesota Power’s SO₂ and NO_X emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2013. We are unable to predict any additional compliance costs we might incur as a result of the CSAPR.

Regional Haze. The federal Regional Haze Rule requires states to submit SIPs to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the first phase of the Regional Haze Rule, certain large stationary sources, built between 1962 and 1977, with emissions contributing to visibility impairment, are required to install emission controls, known as Best Available Retrofit Technology (BART). We have two steam units, Boswell Unit 3 and Taconite Harbor Unit 3, subject to BART requirements.

The MPCA requested that companies with BART-eligible units complete and submit a BART emissions control retrofit study, which was completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirements for that unit. In December 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.

Due to legal challenges at both the state and federal levels, there is currently no applicable compliance deadline for the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation date to bring Taconite Harbor Unit 3 into compliance. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC in November 2013, we plan to retire Taconite Harbor Unit 3 in 2015. We believe that the Taconite Harbor Unit 3 retirement will be accomplished before any compliance deadline takes effect.

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 $310 million through 2016, of which $77.0 million was spent through March 31, 2014. Our minimum payment obligation for the environmental upgrade is $101.0 million for 2014 and $58.2 million for 2015. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in an order dated November 12, 2013, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015, to position the Company for MATS compliance. On January 9, 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.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2011, a final rule was published in the Federal Register for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT). The rule was stayed by the EPA in May 2011, to allow the EPA time to consider additional comments received. The EPA re-proposed the rule in December 2011. In January 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, 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.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Minnesota Mercury Emissions Reduction Act. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, 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. 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 discussed above (see Mercury and Air Toxics Standards (MATS) Rule).

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. The EPA was scheduled to decide upon the 2008 eight-hour ozone standard in July 2011, but has since announced that it is deferring revision of this standard until 2014 or later. Consequently, 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 average fine particulate matter (PM_2.5) and annual PM_2.5 standards; the 24-hour coarse particulate matter standard has remained unchanged. The District of Columbia Circuit Court of Appeals remanded the annual PM_2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM_2.5standards in June 2012.

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 more stringent 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 more stringent standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling.

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 believes that most U.S. counties already meet the new standard and plans to finalize designations of attainment by December 2014. For those counties that the EPA does not designate as having already met the requirements of the new standard, specific dates for required attainment will depend on technology availability, state permitting goals, potential legal challenges and other factors. Minnesota is anticipating that it will retain 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. 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 receipt of EPA guidance to states for preparing the SIP submittal. Guidance was expected in 2013 and has been delayed.

In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year. However, in April 2012, the MPCA notified Minnesota Power that such modeling had been suspended as a result of the EPA’s announcement that the June 2013 SIP submittals would no longer require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The MPCA is awaiting updated EPA guidance and will communicate with affected sources once the MPCA has more information on how the state will meet the EPA’s SIP requirements. 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 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Climate Change. The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change 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, as further described below.

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the final 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 March 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) 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. The EPA also reaffirmed its plans to propose NSPS or regulatory guidelines for existing fossil fuel-fired electric generating units by June 1, 2014, and to finalize such rules by June 1, 2015. The EPA is soliciting feedback as to the approaches the EPA should consider for regulation of CO₂ under the NSPS provisions of the Clean Air Act. Under the CAP, an approach was described where the EPA will issue regulatory guidelines and objectives to the states, which in turn will submit SIPs for EPA approval that demonstrate how the state will meet or surpass achievement of the EPA targeted objectives. The CAP directs the EPA to require states to submit such SIPs by June 30, 2016.

Minnesota has already initiated several measures consistent with those called for under the CAP. Minnesota Power has also announced its “EnergyForward” strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. In October 2013, the Supreme Court granted review of the Circuit Court’s decision, with such review limited to the question of whether EPA’s regulation of GHGs under the PSD provisions of the Clean Air Act and the Tailoring Rule was permissible. The Supreme Court’s decision, which is expected in the second quarter of 2014, is not expected to affect EPA’s authority to regulate CO₂ from fossil fuel-fired electric generating units under the NSPS provisions of the Clean Air Act, but may affect the timing of such regulations.

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. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation 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. State officials have indicated that they will appeal the decision.

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

Clean Water Act - Aquatic Organisms. In 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 killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011, and the EPA has announced its intention to issue the final rule by May 16, 2014. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

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. Instead of proposing a single rule, the EPA proposed eight “options,” of which four are “preferred”. 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, with public comments due in September 2013. The EPA has agreed 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.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash. The EPA has committed to determine whether or not a final rule will be issued under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous) by December 19, 2014, and may publish the final rule at that time, or announce its schedule for such publication. We are unable to predict the 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.

Other Matters

BNI Coal. As of March 31, 2014, BNI Coal had surety bonds outstanding of $29.9 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit with CoBANK ACB for an additional $2.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $32.5 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.

ALLETE Properties. As of March 31, 2014, 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 $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

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, 2014, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2013) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2013). 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.

ALLETE Clean Energy. In January 2014, ALLETE Clean Energy acquired three wind energy facilities–Lake Benton, Storm Lake and Condon–from AES. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. (See Note 4. Acquisition.)

Bonneville Power Administration (Bonneville). Condon has entered into a long-term PPA with Bonneville. Under this agreement, Bonneville has the right and obligation to purchase the output of the facility through September 2022. The agreement contains a fixed price per MWh which is adjusted annually for inflation.

Northern States Power Company (NSP). Lake Benton has entered into a long-term PPA with NSP where NSP purchases the output and capacity of the facility through June 2028. The agreement includes a fixed price per MWh, subject to a curtailment provision and scheduled price changes.

Interstate Power and Light Company (IPL). Storm Lake has entered into two long-term PPAs with IPL through April 2019 and June 2032, respectively. Under these agreements, IPL purchases approximately 219,000 and 26,000 MWh of energy, respectively, which in the aggregate is the expected annual output of the facility. Both PPAs have fixed prices per MWh throughout the contract terms, subject to scheduled price changes.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Legal Proceedings.

United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. In response to a Motion for Summary Judgment by Minnesota Power, the Sixth Judicial District for the State of Minnesota dismissed all of plaintiffs’ claims in an August 2013 order. In October 2013, the plaintiffs’ appealed the decision to the Minnesota Court of Appeals. The Company has filed a response to the appeal and the appeal will be heard by the Minnesota Court of Appeals on May 21, 2014. As of March 31, 2014, a potential loss is not currently probable or reasonably estimable.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act, which it supplemented in March 2014. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of March 31, 2014, because a potential loss is not currently probable or reasonably estimable.

Other. 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, 2014
Operations and Significant Accounting Policies [Abstract]
Inventories [Policy Text Block]	Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.
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]	New Accounting Standards. Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, the FASB issued an accounting standard update on the financial statement presentation of unrecognized tax benefits when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward. To the extent an NOL carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from the disallowance of a tax position or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This guidance was adopted beginning with the quarter ending March 31, 2014, and did not have a material impact on our consolidated financial position, results of operations, or cash flows. 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 will be effective beginning with the quarter ending March 31, 2015, and applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.
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 impairment on a quarterly basis and no impairments were recorded for the quarter ended March 31, 2014 (none for the year ended December 31, 2013).
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.
Derivatives [Policy Text Block]	Changes in the fair value of the Swaps were recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income (Loss) related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.
Fair Value Measurement [Policy Text Block]	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.
Fair Value Transfers [Policy Text Block]	The Company’s policy is to recognize transfers in and transfers out of a given level as of the actual date of the event or of the change in circumstances that caused the transfer.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities represent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.
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 become 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, 2014

Operations and Significant Accounting Policies [Abstract]

Inventories [Table Text Block]



Inventories	March 31, 2014		December 31, 2013
Millions
Fuel		$16.3		$13.1
Materials and Supplies	52.6		46.2
Total Inventories		$68.9		$59.3

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	March 31, 2014		December 31, 2013
Millions
Deferred Fuel Adjustment Clause		$22.1		$23.0
Other	11.3		12.1
Total Prepayments and Other Current Assets		$33.4		$35.1

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



Other Current Liabilities	March 31, 2014		December 31, 2013
Millions
Customer Deposits		$24.1		$26.0
Power Purchase Agreements (a)	13.1		—
Other	24.0		26.6
Total Other Current Liabilities		$61.2		$52.6


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisitions).

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Non-Current Liabilities	March 31, 2014		December 31, 2013
Millions
Asset Retirement Obligation		$89.2		$81.8
Power Purchase Agreements (a)	96.4		—
Other	43.7		45.4
Total Other Non-Current Liabilities		$229.3		$127.2


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisitions).

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



For the Three Months Ended March 31,	2014		2013
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$12.4		$12.0
Cash Paid During the Period for Income Taxes		$0.2		$0.5
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(22.6)		$(26.2)
Capitalized Asset Retirement Costs		$0.6		$1.9
AFUDC – Equity		$1.8		$1.1
ALLETE Common Stock Contributed to the Pension Plan		$19.5	—

Business Segments (Tables)

3 Months Ended

Mar. 31, 2014

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2014
Operating Revenue		$296.5			$264.2			$32.3
Fuel and Purchased Power Expense	96.2			96.2			—
Operating and Maintenance Expense	119.8			90.2			29.6
Depreciation Expense	32.2			28.8			3.4
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

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2013
Operating Revenue		$263.8			$241.4			$22.4
Fuel and Purchased Power Expense	86.5			86.5			—
Operating and Maintenance Expense	104.7			82.2			22.5
Depreciation Expense	28.2			26.8			1.4
Operating Income (Loss)	44.4			45.9			(1.5		)
Interest Expense	(12.3		)	(10.7		)	(1.6		)
Equity Earnings in ATC	5.2			5.2			—
Other Income	2.7			1.1			1.6
Income (Loss) Before Non-Controlling Interest and Income Taxes	40.0			41.5			(1.5		)
Income Tax Expense (Benefit)	7.5			9.4			(1.9		)
Net Income	32.5			32.1			0.4
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$32.5			$32.1			$0.4

As of March 31, 2013
Total Assets		$3,251.3			$2,967.9			$283.4
Property, Plant and Equipment – Net		$2,366.7			$2,300.8			$65.9
Accumulated Depreciation		$1,179.8			$1,121.8			$58.0
Capital Additions		$43.1			$42.6			$0.5

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References+ Details

Investments (Tables)

3 Months Ended

Mar. 31, 2014

Investments [Abstract]

Other Investments and ALLETE Properties [Table Text Block]



Other Investments	March 31, 2014		December 31, 2013
Millions
ALLETE Properties		$90.1		$89.9
Available-for-sale Securities (a)	19.8		17.7
Cash Equivalents (b)	3.9		34.2
Other	2.6		4.5
Total Other Investments		$116.4		$146.3


(a)	As of March 31, 2014, 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 $4.0 million, in three years to less than five years was $1.3 million, and in five or more years was $4.3 million.


(b)	During the quarter ended March 31, 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.

NOTE 3. INVESTMENTS (Continued)



ALLETE Properties	March 31, 2014		December 31, 2013
Millions
Land Inventory Beginning Balance		$85.4		$86.5
Cost of Sales	—		(1.5		)
Other	0.2		0.4
Land Inventory Ending Balance	85.6		85.4
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4		1.4
Other	3.1		3.1
Total Real Estate Assets		$90.1		$89.9

Acquisitions (Table)

3 Months Ended

Mar. 31, 2014

Acquisitions [Abstract]

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



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	12.4
Property, Plant and Equipment – Net	161.2
Other Non-Current Assets (a)	8.1
Total Assets Acquired		$185.5
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	10.1
Non-Controlling Interest (c)	10.6
Total Liabilities and Non-Controlling Interest Assumed	158.6
Net Identifiable Assets Acquired		$26.9


(a)	Included in Other Non-Current Assets was the fair value estimate of $0.3 million for the option to purchase Armenia Mountain in 2015, and preliminary goodwill of $1.9 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 preliminary purchase price accounting valued the non-controlling interest of Lake Benton, Storm Lake and Condon at fair value primarily on the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm lake was subsequently purchased by ALLETE Clean Energy.

Fair Value (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of March 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$9.8	—		—		$9.8
Available-for-sale – Corporate Debt Securities	—			$10.0	—	10.0
Cash Equivalents	3.9		—		—	3.9
Total Fair Value of Assets		$13.7		$10.0	—		$23.7

Liabilities:
Deferred Compensation (b)	—			$18.7	—		$18.7
Derivatives – Interest Rate Swap (c)	—		0.5		—	0.5
Total Fair Value of Liabilities	—			$19.2	—		$19.2
Total Net Fair Value of Assets (Liabilities)		$13.7	$(9.2)		—		$4.5


(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 and Other Non-Current Liabilities on the Consolidated Balance Sheet.

NOTE 6. FAIR VALUE (Continued)



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.9	—		—		$7.9
Available-for-sale – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9

Liabilities:
Deferred Compensation (b)	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap (c)	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5


(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 and Other Non-Current Liabilities on the Consolidated Balance Sheet.

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
March 31, 2014	$1,213.6	$1,282.9
December 31, 2013	$1,110.2	$1,131.7

- Definition

Tabular disclosure of the fair value of financial instruments, including financial assets and financial liabilities, and the measurements of those instruments, assets, and liabilities.

+ References+ Details

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2014

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	March 31, 2014		December 31, 2013
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.1		$23.0
Total Current Regulatory Assets	22.1		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	164.7		164.1
Income Taxes	36.2		35.3
Asset Retirement Obligations	16.7		16.0
Cost Recovery Riders (c)	40.3		39.6
PPACA Income Tax Deferral	5.0		5.0
Other	4.1		3.8
Total Non-Current Regulatory Assets	267.0		263.8
Total Regulatory Assets		$289.1		$286.8

Non-Current Regulatory Liabilities
Income Taxes		$17.1		$17.0
Plant Removal Obligations	20.4		19.7
Wholesale and Retail Contra AFUDC	23.7		19.7
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	15.9		16.3
Other	12.8		8.3
Total Non-Current Regulatory Liabilities		$89.9		$81.0


(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 14. Pension and Other Postretirement Benefit Plans).


(c)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC (Tables)

3 Months Ended

Mar. 31, 2014

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, 2013		$114.6
Cash Investments	1.2
Equity in ATC Earnings	5.1
Distributed ATC Earnings	(4.3		)
Equity Investment Balance as of March 31, 2014		$116.6

ATC Summarized Financial Data [Table Text Block]

ATC’s summarized financial data for the quarters ended March 31, 2014 and 2013, is as follows:



	Quarter Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2014		2013
Millions
Revenue		$163.3	$151.8
Operating Expense	78.6		69.8
Other Expense	21.6		21.5
Net Income		$63.1	$60.5
ALLETE’s Equity in Net Income		$5.1	$5.2

Short-Term and Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2014

Short-Term and Long-Term Debt [Abstract]

First Mortgage Bonds Issuance [Table Text Block]



Issue Date (on or about)	Maturity Date	Principal Amount	Interest Rate
March 4, 2014	March 15, 2024	$60 Million	3.69%
March 4, 2014	March 15, 2044	$40 Million	4.95%
June 26, 2014	July 15, 2022	$75 Million	3.40%
June 26, 2014	July 15, 2044	$40 Million	5.05%

- Definition

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

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.4-08.(e),(f))

-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 835

-SubTopic 30

-Section 55

-Paragraph 8

-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 835

-SubTopic 30

-Section 45

-Paragraph 2

-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 835

-SubTopic 30

-Section 45

-Paragraph 1A

-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 505

-SubTopic 10

-Section 50

-Paragraph 3

-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 6: http://www.xbrl.org/2003/role/presentationRef

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 02

-Paragraph 22

-Article 5

Reference 7: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 210

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.5-02.22)

-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 8: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 505

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-Name Accounting Standards Codification

-Topic 505

-SubTopic 10

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-Paragraph 7

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Reference 10: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 505

-SubTopic 10

-Section 50

-Paragraph 8

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-Publisher FASB

-Name Accounting Standards Codification

-Topic 942

-SubTopic 470

-Section 50

-Paragraph 3

-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

+ Details

Income Tax Expense (Tables)

3 Months Ended

Mar. 31, 2014

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended
	March 31,
	2014			2013
Millions
Current Tax Expense (Benefit)
Federal (a)	—				$0.2
State (a)	—			—
Total Current Tax Expense (Benefit)	—			0.2
Deferred Tax Expense (Benefit)
Federal		$6.3			$5.8
State	2.7			1.7
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Tax Expense	8.8			7.3
Total Income Tax Expense		$8.8			$7.5

(a)

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

3 Months Ended

Mar. 31, 2014

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

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

Changes in accumulated other comprehensive loss, net of tax, for the quarters ended March 31, 2014 and 2013, 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
For the Quarter 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 Income	—	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)

For the Quarter Ended March 31, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)	$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income (Loss) Before Reclassifications	0.5	(2.9)	0.1	(2.3)
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(0.5)	3.2	—	2.7
Net Other Comprehensive Income	—	0.3	0.1	0.4
Ending Accumulated Other Comprehensive Loss	$(0.1)	$(21.2)	$(0.3)	$(21.6)

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

Reclassifications from accumulated other comprehensive loss for the quarters ended March 31, 2014 and 2013, were as follows:



	Quarter Ended	Quarter Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	March 31,	March 31,
	2014	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	—	$0.8
Income Taxes (b)	—	(0.3)
Total, Net of Income Taxes	—	$0.5

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.1	$0.5
Actuarial Gains and Losses (c)	(0.6)	(5.7)
Total	(0.5)	(5.2)
Income Taxes (b)	0.2	2.0
Total, Net of Income Taxes	$(0.3)	$(3.2)
Total Reclassifications	$(0.3)	$(2.7)


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


(b)	Included in Income Tax Expense on the Consolidated Statement of Income.


(c)	Defined benefit pension and other postretirement benefit 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 14. Pension and Other Postretirement Benefit Plans).

Operations and Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Jan. 30, 2014

Dec. 31, 2013

Operations and Significant Accounting Policies [Abstract]

Restricted Cash and Cash Equivalents, Noncurrent

$ 5.3

Escrow Deposit

5.4

Inventories [Abstract]

Fuel

16.3

13.1

Materials and Supplies

52.6

46.2

Total Inventories

68.9

59.3

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

22.1

23.0

Other

11.3

12.1

Total Prepayments and Other Current Assets

33.4

35.1

Other Current Liabilites [Abstract]

Customer Deposits

24.1

26.0

Power Purchase Agreement

13.1

^[1]

12.4

^[1]

Other

24.0

26.6

Total Other Current Liabilities

61.2

52.6

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

89.2

81.8

Power Purchase Agreement

96.4

^[1]

99.4

^[1]

Other

43.7

45.4

Total Other Non-Current Liabilities

229.3

127.2

Supplemental Statement of Cash Flows Information [Abstract]

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

12.4

12.0

Cash Paid During the Period for Income Taxes

0.2

0.5

Noncash Investing and Financing Activities [Abstract]

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

(22.6)

(26.2)

Capitalized Asset Retirement Costs

0.6

1.9

AFUDC - Equity

1.8

1.1

ALLETE Common Stock Contributed to the Pension Plan

$ 19.5

$ 0

[1]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisitions).

Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Business Segments [Line Items]
Operating Revenue	$ 296.5	$ 263.8
Fuel and Purchased Power Expense	96.2	86.5
Operating and Maintenance Expense	119.8	104.7
Depreciation Expense	32.2	28.2
Operating Income (Loss)	48.3	44.4
Interest Expense	(12.8)	(12.3)
Equity Earnings in ATC	5.1	5.2
Other Income	2.0	2.7
Income (Loss) Before Non-Controlling Interest and Income Taxes	42.6	40.0
Income Tax Expense (Benefit)	8.8	7.5
Net Income (Loss)	33.8	32.5
Less: Non-Controlling Interest in Subsidiaries	0.3	0
Net Income (Loss) Attributable to ALLETE	33.5	32.5
Total Assets	3,749.2	3,251.3	3,476.8
Property, Plant and Equipment - Net	2,905.1	2,366.7	2,576.5
Accumulated Depreciation	1,266.7	1,179.8
Capital Additions	195.2	43.1
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue	264.2	241.4
Fuel and Purchased Power Expense	96.2	86.5
Operating and Maintenance Expense	90.2	82.2
Depreciation Expense	28.8	26.8
Operating Income (Loss)	49.0	45.9
Interest Expense	(11.5)	(10.7)
Equity Earnings in ATC	5.1	5.2
Other Income	1.8	1.1
Income (Loss) Before Non-Controlling Interest and Income Taxes	44.4	41.5
Income Tax Expense (Benefit)	10.5	9.4
Net Income (Loss)	33.9	32.1
Less: Non-Controlling Interest in Subsidiaries	0	0
Net Income (Loss) Attributable to ALLETE	33.9	32.1
Total Assets	3,335.5	2,967.9
Property, Plant and Equipment - Net	2,671.3	2,300.8
Accumulated Depreciation	1,202.9	1,121.8
Capital Additions	193.5	42.6
Investments and Other [Member]
Business Segments [Line Items]
Land in Minnesota (in acres)	5,000
Operating Revenue	32.3	22.4
Fuel and Purchased Power Expense	0	0
Operating and Maintenance Expense	29.6	22.5
Depreciation Expense	3.4	1.4
Operating Income (Loss)	(0.7)	(1.5)
Interest Expense	(1.3)	(1.6)
Equity Earnings in ATC	0	0
Other Income	0.2	1.6
Income (Loss) Before Non-Controlling Interest and Income Taxes	(1.8)	(1.5)
Income Tax Expense (Benefit)	(1.7)	(1.9)
Net Income (Loss)	(0.1)	0.4
Less: Non-Controlling Interest in Subsidiaries	0.3	0
Net Income (Loss) Attributable to ALLETE	(0.4)	0.4
Total Assets	413.7	283.4
Property, Plant and Equipment - Net	233.8	65.9
Accumulated Depreciation	63.8	58.0
Capital Additions	$ 1.7	$ 0.5

Investments (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

Mar. 31, 2014

Dec. 31, 2013

Investments [Abstract]

ALLETE Properties

$ 90.1

$ 89.9

Available-for-sale Securities

19.8

^[1]

17.7

^[1]

Cash Equivalents

3.9

^[2]

34.2

^[2]

Other

2.6

4.5

Total Other Investments

116.4

146.3

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

4.0

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

1.3

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

4.3

ALLETE Properties [Rollforward]

Land Inventory Beginning Balance

85.4

86.5

Cost of Sales

(1.5)

Other

0.2

0.4

Land Inventory Ending Balance

85.6

85.4

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

1.4

Other

3.1

Total Real Estate Assets

90.1

89.9

Impairment of Real Estate

Long-Term Finance Receivables, Allowance

$ 0.6

[1]	As of March 31, 2014, 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 $4.0 million, in three years to less than five years was $1.3 million, and in five or more years was $4.3 million.
[2]	During the quarter ended March 31, 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.

Acquisitions (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

3 Months Ended

Feb. 11, 2014

Jan. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Jan. 30, 2014

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

$ 26.9

Assets [Abstract]

Cash and Cash Equivalents

3.8

Other Current Assets

12.4

Property, Plant and Equipment - Net

161.2

Other Non-Current Assets

8.1

^[1]

Total Assets Acquired

185.5

Liabilities [Abstract]

Other Current Liabilities

15.2

^[2]

Long-term Debt Due Within One Year

2.2

Long-term Debt

21.1

Power Purchase Agreement

99.4

96.4

^[3]

Other Non-Current Liabilities

10.1

Non-Controlling Interest

10.6

^[4]

Total Liabilities and Non-Controlling Interest Assumed

158.6

Net Identifiable Assets Acquired

26.9

Power Purchase Agreement

12.4

13.1

^[3]

Business Combination, Acquisition Related Costs

1.4

Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests

6.0

Armenia Mountain [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Armenia Mountain

Generating Capacity (MW)

101

Liabilities [Abstract]

Purchase option

0.3

Goodwill

$ 1.9

Storm Lake [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Storm Lake

Generating Capacity (MW)

Condon [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Condon

Generating Capacity (MW)

Lake Benton [Member]

Business Acquisition [Line Items]

Business Acquisition, Name of Acquired Entity

Lake Benton

Generating Capacity (MW)

104

[1]	Included in Other Non-Current Assets was the fair value estimate of $0.3 million for the option to purchase Armenia Mountain in 2015, and preliminary goodwill of $1.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[2]	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.
[3]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisition on January 30, 2014 (see Note 4. Acquisitions).
[4]	The preliminary purchase price accounting valued the non-controlling interest of Lake Benton, Storm Lake and Condon at fair value primarily on the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm lake was subsequently purchased by ALLETE Clean Energy.

Derivatives - Derivative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Interest Rate Swap [Member]
Derivative [Line Items]
Interest Rate Swap Variable Rate Basis	one-month LIBOR
Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	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 assessments of hedge effectiveness resulted in no ineffectiveness recorded for the quarter ended March 31, 2014.
Interest Rate Swap Liability	$ 0.5	$ 0.6
Interest Rate Swap Liability, Other Non-Current Liabilities	0.3	0.3
Interest Rate Swap Liability, Other Current Liabilities	$ 0.2	$ 0.3
Interest Rate Swap Member Effective August 25, 2011 [Member]
Derivative [Line Items]
Interest Rate Swap Fixed Interest Rate	0.825%
Interest Rate Swap Member Effective August 26, 2014 [Member]
Derivative [Line Items]
Interest Rate Swap Fixed Interest Rate	0.75%

Fair Value - Recurring Fair Value Measures (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Investments [Abstract]

Cash Equivalents

$ 3.9

^[1]

$ 34.2

^[1]

Fair Value [Abstract]

Fair Value Activity in Level 3

Fair Value Hierarchy Transfers, All Levels

Recurring Fair Value Measurements [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

9.8

^[2]

7.9

^[2]

Available-for-sale - Corporate Debt Securities

10.0

^[2]

9.8

^[2]

Cash Equivalents

3.9

^[2]

34.2

^[2]

Total Fair Value of Assets

23.7

51.9

Liabilities [Abstract]

Deferred Compensation

18.7

^[3]

16.8

^[3]

Derivatives - Interest Rate Swap

0.5

^[4]

0.6

^[4]

Total Fair Value of Liabilities

19.2

17.4

Total Net Fair Value of Assets (Liabilities)

4.5

34.5

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

Investments [Abstract]

Available-for-sale - Equity Securities

9.8

^[2]

7.9

^[2]

Available-for-sale - Corporate Debt Securities

^[2]

Cash Equivalents

3.9

^[2]

34.2

^[2]

Total Fair Value of Assets

13.7

42.1

Liabilities [Abstract]

Deferred Compensation

^[3]

Derivatives - Interest Rate Swap

^[4]

Total Fair Value of Liabilities

Total Net Fair Value of Assets (Liabilities)

13.7

42.1

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

Investments [Abstract]

Available-for-sale - Equity Securities

^[2]

Available-for-sale - Corporate Debt Securities

10.0

^[2]

9.8

^[2]

Cash Equivalents

^[2]

Total Fair Value of Assets

10.0

9.8

Liabilities [Abstract]

Deferred Compensation

18.7

^[3]

16.8

^[3]

Derivatives - Interest Rate Swap

0.5

^[4]

0.6

^[4]

Total Fair Value of Liabilities

19.2

17.4

Total Net Fair Value of Assets (Liabilities)

(9.2)

(7.6)

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

Investments [Abstract]

Available-for-sale - Equity Securities

^[2]

Available-for-sale - Corporate Debt Securities

^[2]

Cash Equivalents

^[2]

Total Fair Value of Assets

Liabilities [Abstract]

Deferred Compensation

^[3]

Derivatives - Interest Rate Swap

^[4]

Total Fair Value of Liabilities

Total Net Fair Value of Assets (Liabilities)

$ 0

[1]	During the quarter ended March 31, 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.
[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 Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.

Fair Value - Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,213.6	$ 1,110.2
Long-term Debt, Including Current Portion - Fair Value	$ 1,282.9	$ 1,131.7

- Definition

Carrying amount of long-term debt, net of unamortized discount or premium, including current and noncurrent amounts. Includes, but not limited to, notes payable, bonds payable, debentures, mortgage loans and commercial paper. Excludes capital lease obligations.

+ References+ Details

Regulatory Matters - Utility Rates (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014 Bison Wind Energy Center [Member] MW	Mar. 31, 2014 Bison 4 [Member] MW	Jun. 01, 2011 MPUC 2010 Minnesota Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Mar. 31, 2014 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Years Customers	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Retail Customers [Member]
Rate Regulation [Line Items]
Approved Rate of Return on Common Equity			10.38%		10.90%
Approved Percentage of Capital Structure Related to Equity			54.29%
Number of Customers				16
Length of Notice Required to Terminate (in Years)				3
Generating Capacity (MW)	292	205
Estimated Capital Expenditures		$ 345
Capital Cost Spent to Date		$ 187.1

Regulatory Matters - Regulatory Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified

Mar. 31, 2014

Dec. 31, 2013

Regulatory Assets and Liabilities [Line Items]

Total Current Regulatory Assets

$ 22.1

^[1]

$ 23.0

^[1]

Non-Current Regulatory Assets

267.0

263.8

Total Regulatory Assets

289.1

286.8

Non-Current Regulatory Liabilities

89.9

81.0

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

17.1

17.0

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

20.4

19.7

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

23.7

19.7

Deferred Fuel [Member]

Regulatory Assets and Liabilities [Line Items]

Total Current Regulatory Assets

22.1

^[1]

23.0

^[1]

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

164.7

^[2]

164.1

^[2]

Non-Current Regulatory Liabilities

15.9

^[2]

16.3

^[2]

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

36.2

35.3

Asset Retirement Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

16.7

16.0

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

40.3

^[3]

39.6

^[3]

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

4.1

3.8

Non-Current Regulatory Liabilities

$ 12.8

$ 8.3

[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 14. Pension and Other Postretirement Benefit Plans).
[3]	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		1 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Apr. 30, 2014 Subsequent Event [Member]
Investment in ATC [Abstract]
Ownership Percentage	8.00%
Approved Return on Common Equity	12.20%
Equity Method Investment, Expected Additional Investment	$ 3.4
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2013	114.6
Cash Investments	1.2		1.2
Equity Earnings in ATC	5.1	5.2
Distributed ATC Earnings	(4.3)
Equity Investment Balance as of March 31, 2014	116.6
ATC Summarized Financial Data [Abstract]
Revenue	163.3	151.8
Operating Expense	78.6	69.8
Other Expense	21.6	21.5
Net Income	63.1	60.5
ALLETE's Equity in Net Income	5.1	5.2
Subsequent Event [Line Items]
Cash Investments	$ 1.2		$ 1.2

Short-Term and Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Mar. 04, 2014	Dec. 10, 2013	Mar. 31, 2014	Jan. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Short-Term Debt Outstanding			$ 11.1		$ 27.2
Short-Term Debt Outstanding, Subsequently Matured			11.1		27.2
Long-Term Debt Outstanding			1,202.5		1,083.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt				23.3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt				2.2
Expected Proceeds from Future Issuance of First Mortgage Bonds		215.0
Proceeds from Issuance of First Mortgage Bonds	100.0
ALLETE Bonds 4.86% Series Due 2013 [Member]
Debt Instrument [Line Items]
Short-Term Debt Outstanding, Subsequently Matured					18.0
ALLETE Bonds 3.69% Due March2024 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bonds	60.0
Debt Instrument, Interest Rate, Stated Percentage	3.69%
ALLETE Bonds 4.95% Due March2044 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bonds	40.0
Debt Instrument, Interest Rate, Stated Percentage	4.95%
ALLETE Bonds 3.40% Due July2022 [Member]
Debt Instrument [Line Items]
Expected Proceeds from Future Issuance of First Mortgage Bonds		75.0
Future Debt Instrument, Interest Rate, Stated Percentage		3.40%
ALLETE Bonds 5.05% Due July2044 [Member]
Debt Instrument [Line Items]
Expected Proceeds from Future Issuance of First Mortgage Bonds		$ 40.0
Future Debt Instrument, Interest Rate, Stated Percentage		5.05%

Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 1.8	$ 1.1
Gain on Sale of Available-for-sale Securities	0	0.8
Investments and Other Income	0.2	0.8
Total Other Income	$ 2.0	$ 2.7

Income Tax Expense (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Current Tax Expense (Benefit) [Abstract]

Federal

$ 0

^[1]

$ 0.2

^[1]

State

^[1]

Total Current Tax Expense (Benefit)

0.2

Deferred Tax Expense (Benefit) [Abstract]

Federal

6.3

5.8

State

2.7

1.7

Investment Tax Credit Amortization

(0.2)

Total Deferred Tax Expense

8.8

7.3

Total Income Tax Expense

8.8

7.5

Effective Income Tax Rate

20.70%

18.80%

Federal Statutory Income Tax Rate

41.00%

Uncertain Tax Positions [Abstract]

Gross Unrecognized Tax Benefits

1.2

Unrecognized Tax Benefits that Would Favorably Impact Effective Tax Rate

$ 0.2

[1]

Reclassifications out of Accumulated Other Comprehensive Income (Loss) (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

$ (16.8)

$ (21.6)

$ (17.1)

$ (22.0)

Other Comprehensive Income (Loss) Before Reclassifications

(2.3)

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

0.3

2.7

Net Other Comprehensive Income

0.3

0.4

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(0.5)

(5.2)

Other Income (Expense) - Other [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

^[1]

0.8

^[1]

Income Tax Expense [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

^[2]

(0.3)

^[2]

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

0.2

^[2]

2.0

^[2]

Operating Expenses - Operating and Maintenance [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

0.1

^[3]

0.5

^[3]

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

(0.6)

^[3]

(5.7)

^[3]

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

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

(0.1)

Other Comprehensive Income (Loss) Before Reclassifications

0.5

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

(0.5)

Net Other Comprehensive Income

Defined Benefit Pension and Other Postretirement Items [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

(16.4)

(21.2)

(16.7)

(21.5)

Other Comprehensive Income (Loss) Before Reclassifications

(2.9)

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

0.3

3.2

Net Other Comprehensive Income

0.3

Gains and Losses on Cash Flow Hedge [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

(0.3)

(0.4)

Other Comprehensive Income (Loss) Before Reclassifications

0.1

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

Net Other Comprehensive Income

$ 0

$ 0.1

[1]	Included in Other Income (Expense) – Other on the Consolidated Statement of Income.
[2]	Included in Income Tax Expense on the Consolidated Statement of Income.
[3]	Defined benefit pension and other postretirement benefit 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 14. Pension and Other Postretirement Benefit Plans)

Earnings Per Share and Common Stock (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	0 Months Ended		3 Months Ended
	Mar. 04, 2014	Feb. 26, 2014	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share and Common Stock [Abstract]
Anti-dilutive Shares Excluded from Diluted EPS Computation			0	0.1
Earnings Per Share - Basic [Abstract]
Net Income			$ 33.5	$ 32.5
Average Common Shares			41.4	38.9
Earnings Per Share			$ 0.81	$ 0.83
Earnings Per Share - Diluted [Abstract]
Net Income			33.5	32.5
Average Common Shares			41.6	39.0
Earnings Per Share			$ 0.80	$ 0.83
Dilutive Securities (Shares)			0.2	0.1
Forward Contract Indexed to Issuer's Equity, Indexed Shares		2.8
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share		$ 48.01
Common Stock, Shares, Issued - Option Agreement	0.4
Proceeds from Issuance or Sale of Equity - Option Agreement	20.2
Forward Contract Indexed to Issuer's Equity, Dilutive effect			0
Forward Contract Indexed to Issuer's Equity, Initial Fair Value		0
Stock Issued During Period, Shares, Employee Benefit Plan			0.4
Stock Issued During Period, Value, Employee Benefit Plan			$ 19.5

Pension and Other Postretirement Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	$ 2.1	$ 2.5
Interest Cost	7.4	6.5
Expected Return on Plan Assets	(9.6)	(8.8)
Amortization of Prior Service Costs (Credits)	0.1	0.1
Amortization of Net Loss	3.6	5.3
Net Periodic Benefit Expense	3.6	5.6
Contributions	19.5	0
Estimated Future Contributions	0
Other Postretirement [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	0.9	1.0
Interest Cost	1.8	1.7
Expected Return on Plan Assets	(2.6)	(2.5)
Amortization of Prior Service Costs (Credits)	(0.6)	(0.6)
Amortization of Net Loss	0.1	0.4
Net Periodic Benefit Expense	(0.4)	0
Contributions	0	10.8
Estimated Future Contributions	$ 0

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Debt Outstanding	$ 423,400,000
Annual Debt Service	44,000,000
Power Purchased Under Long-term Contracts	16,800,000	16,300,000
Interest Expense	2,500,000	2,600,000
Square Butte PPA [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Capacity (MW)	455
Output Entitlement	50.00%
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
Term of Contract (Years)	25
Fixed Capacity Charges	0
Oliver Wind II PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Term of Contract (Years)	25
Fixed Capacity Charges	$ 0
Manitoba Hydro PPA (expires April 2015) [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)	1,000,000
Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Term of Contract (Years)	15
Interstate Power and Light Company PPA (expires April 2019) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh)	219,000
Interstate Power and Light Company (expires June 2032) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh)	26,000

Commitments, Guarantees and Contingencies - North Dakota Wind Development (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014 kV Miles
DC Transmission Line from Square Butte [Member]
North Dakota Wind Development [Line Items]
Transmission Line Length (Miles)	465
Transmission Line Capacity (kV)	250
Bison Wind Energy Center [Member]
North Dakota Wind Development [Line Items]
Generating Capacity (MW)	292
Bison 4 [Member]
North Dakota Wind Development [Line Items]
Generating Capacity (MW)	205
Estimated Capital Expenditures	$ 345
Capital Cost Spent to Date	$ 187.1

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) (Coal and Transportation [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Coal and Transportation [Member]
Coal, Rail and Shipping Contracts [Line Items]
Minimum Annual Payment Obligation, Current Year	$ 26.0
Minimum Annual Payment Obligation, Year Two	$ 4.0

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Leasing Agreements [Line Items]
Operating Leases, Future Minimum Payments, Due in Current Year	$ 12.1
Operating Leases, Future Minimum Payments, Due in Year Two	11.5
Operating Leases, Future Minimum Payments, Due in Year Three	9.5
Operating Leases, Future Minimum Payments, Due in Year Four	8.7
Operating Leases, Future Minimum Payments, Due in Year Five	7.4
Operating Leases, Future Minimum Payments, Due Thereafter	29.2
BNI Coal Dragline Lease [Member]
Leasing Agreements [Line Items]
Termination Fee	3.0
Operating Leases, Future Minimum Payments, Due in Current Year	$ 2.8

Commitments, Guarantees and Contingencies - Transmission (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	3
Capital Cost Spent to Date	$ 85.7
CapX2020 [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	100
CapX2020 [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	110
Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	220
Transmission Line Capacity (kV)	500
Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	500
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	$ 650
Project in Progress [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	1
Completed Project [Member] [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	2

Commitments, Guarantees and Contingencies - Environmental Matters (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 310
Capital Cost Spent to Date	77.0
Other Commitment, Due in Next Twelve Months	101.0
Other Commitment, Due in Second Year	$ 58.2

Commitments, Guarantees and Contingencies - Other Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 Years	Dec. 31, 2013
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Surety Bond Amount	$ 29.9
Reclamation Letter of Credit	2.6
Total Current Estimated Reclamation Liability	32.5
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Surety Bond and Letters of Credit	10.2
Development and Maintenance Obligations	7.4
Town Center Community Development District [Member]
Guarantor Obligations [Line Items]
Bond Amount	26.4
Bond Interest Rate	6.00%
Bond Term (Years)	31
Ownership of Property Benefited	73.00%	73.00%
Annual Assessment	1.4
Palm Coast Park Community Development District [Member]
Guarantor Obligations [Line Items]
Bond Amount	31.8
Bond Interest Rate	5.70%
Bond Term (Years)	31
Ownership of Property Benefited	93.00%	93.00%
Annual Assessment	$ 2.1

Derivatives - Hedged Item (Details) (Term Loan [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Term Loan [Member]
Debt Instrument [Line Items]
Term Loan Principal Amount	$ 75.0
Percentage of Debt Hedged by Interest Rate Derivatives	6.00%

Commitments, Guarantees and Contingencies - Legal Proceedings (Details) (Pending Litigation [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Pending Litigation [Member]
Legal Proceedings [Line Items]
Damages Sought	$ 20

Investments - Parentheticals (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Investments Parentheticals [Abstract]
Long-Term Finance Receivables, Allowance	$ 0.6	$ 0.6

Short-Term and Long-Term Debt - Financial Covenants (Details)	3 Months Ended
	Mar. 31, 2014
Financial Covenants [Abstract]
Debt Instrument, Required Indebtedness to Total Capital Ratio	0.65
Debt Instrument, Actual Indebtedness to Total Capital Ratio	0.46

Commitments, Guarantees and Contingencies - Hydro Operations (Details) (Hydro Project [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Hydro Project [Member]
Hydro Operations [Line Items]
Estimated Capital Expenditures	$ 90
Capital Cost Spent to Date	$ 66.4