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Document And Entity Information - USD ($)	3 Months Ended
Document And Entity Information - USD ($)	Mar. 31, 2012	Jun. 30, 2011
Entity Information [Line Items]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 1,488,071,330
Entity Common Stock, Shares Outstanding	38,142,329
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2012

Consolidated Balance Sheet - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Current Assets [Abstract]
Cash and Cash Equivalents	$ 118.2	$ 101.1
Accounts Receivable (Less Allowance of $1.0 and $0.9)	76.7	79.7
Inventories	72.2	69.1
Prepayments and Other	22.9	27.1
Total Current Assets	290.0	277.0
Property, Plant and Equipment - Net	2,002.8	1,982.7
Regulatory Assets	339.3	345.9
Investment in ATC	100.5	98.9
Other Investments	135.7	132.3
Other Non-Current Assets	38.3	39.2
Total Assets	2,906.6	2,876.0
Current Liabilities [Abstract]
Accounts Payable	51.5	71.8
Accrued Taxes	30.8	26.4
Accrued Interest	11.3	12.8
Long-Term Debt Due Within One Year	5.5	5.4
Notes Payable	1.6	1.1
Other	41.8	45.6
Total Current Liabilities	142.5	163.1
Long-Term Debt	856.5	857.9
Deferred Income Taxes	383.4	373.6
Regulatory Liabilities	45.3	43.5
Defined Benefit Pension and Other Postretirement Benefit Plans	254.0	253.5
Other Non-Current Liabilities	111.1	105.1
Total Liabilities	1,792.8	1,796.7
Commitments, Guarantees and Contingencies (Note 13)
ALLETE's Equity [Abstract]
Common Stock Without Par Value, 80 Shares Authorized, 38.1 and 37.5 Shares Outstanding	730.0	705.6
Unearned ESOP Shares	(27.0)	(29.0)
Accumulated Other Comprehensive Loss	(27.5)	(28.9)
Retained Earnings	438.3	431.6
Total Equity	1,113.8	1,079.3
Total Liabilities and Equity	$ 2,906.6	$ 2,876.0

Consolidated Balance Sheet Parenthetical - USD ($) shares in Millions, $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Accounts Receivable, Net [Abstract]
Accounts Receivable, Allowance	$ 1.0	$ 0.9
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	38.1	37.5

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Consolidated Statement of Income [Abstract]
Operating Revenue	$ 240.0	$ 242.2
Operating Expenses [Abstract]
Fuel and Purchased Power	77.1	79.0
Operating and Maintenance	99.9	90.1
Depreciation	24.6	22.3
Total Operating Expenses	201.6	191.4
Operating Income	38.4	50.8
Other Income (Expense) [Abstract]
Interest Expense	(11.0)	(10.7)
Equity Earnings in ATC	4.6	4.4
Other	0.7	0.8
Total Other Expense	(5.7)	(5.5)
Income Before Non-Controlling Interest and Income Taxes	32.7	45.3
Income Tax Expense	8.3	8.2
Net Income	24.4	37.1
Less: Non-Controlling Interest in Subsidiaries	0.0	(0.1)
Net Income Attributable to ALLETE	$ 24.4	$ 37.2
Average Shares of Common Stock [Abstract]
Basic	36.8	34.6
Diluted	36.9	34.7
Basic Earnings Per Share of Common Stock	$ 0.66	$ 1.07
Diluted Earnings Per Share of Common Stock	0.66	1.07
Dividends Per Share of Common Stock	$ 0.46	$ 0.445

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net Income	$ 24.4	$ 37.1
Unrealized Gain on Securities, Net of Income Taxes of $0.7 and $0.6	1.0	0.9
Unrealized Loss on Derivatives, Net of Income Taxes of $(0.1) and $-	(0.1)	0.0
Defined Benefit Pension and Other Postretirement Benefit Plans, Net of Income Taxes of $0.3 and $0.3	0.5	0.4
Total Other Comprehensive Income	1.4	1.3
Total Comprehensive Income	25.8	38.4
Less: Non-Controlling Interest in Subsidiaries	0.0	(0.1)
Comprehensive Income Attributable to ALLETE	$ 25.8	$ 38.5

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

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+ Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to noncontrolling interests, if any. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the economic entity, including both controlling (parent) and noncontrolling interests. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, including any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

This element represents Other Comprehensive Income or Loss, Net of Tax, for the period. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.

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- Definition

Change in accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges, net of tax effect. The after tax effect change includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

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+ Details

- Definition

Appreciation or loss in value (before reclassification adjustment) of the total of unsold securities during the period being reported on, net of tax. Reclassification adjustments include: (1) the unrealized holding gain (loss), net of tax, at the date of the transfer for a debt security from the held-to-maturity category transferred into the available-for-sale category. Also includes the unrealized gain (loss) at the date of transfer for a debt security from the available-for-sale category transferred into the held-to-maturity category; (2) the unrealized gains (losses) realized upon the sale of securities, after tax; and (3) the unrealized gains (losses) realized upon the write-down of securities, after tax.

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- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

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+ Details

Consolidated Statement of Comprehensive Income Parenthetical - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Other Comprehensive Income (Loss), Tax [Abstract]
Unrealized Gain on Securities, Tax	$ 0.7	$ 0.6
Unrealized Loss on Derivatives, Tax	(0.1)	0.0
Defined Benefit Pension and Other Postretirement Benefit Plans, Tax	$ 0.3	$ 0.3

Consolidated Statement of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Activities [Abstract]
Net Income	$ 24.4	$ 37.1
Allowance for Funds Used During Construction	(0.8)	(0.6)
Income from Equity Investments, Net of Dividends	(0.7)	0.0
Gain on Sale of Assets	0.0	(0.7)
Depreciation Expense	24.6	22.3
Amortization of Debt Issuance Costs	0.2	0.2
Deferred Income Tax Expense	8.3	8.1
Share-Based Compensation Expense	0.7	0.6
ESOP Compensation Expense	1.8	1.9
Defined Benefit Pension and Other Postretirement Benefit Expense	6.9	6.2
Bad Debt Expense	0.3	0.2
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	2.7	7.8
Inventories	(3.1)	3.9
Prepayments and Other	4.2	4.1
Accounts Payable	(7.9)	(12.7)
Other Current Liabilities	(0.9)	0.2
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans	0.0	(10.9)
Changes in Regulatory and Other Non-Current Assets	2.1	(2.5)
Changes in Regulatory and Other Non-Current Liabilities	5.7	3.9
Cash from Operating Activities	68.5	69.1
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	0.5	7.0
Payments for Purchase of Available-for-sale Securities	(0.8)	(0.9)
Investment in ATC	(0.8)	(0.8)
Changes to Other Investments	(1.5)	(0.9)
Additions to Property, Plant and Equipment	(53.9)	(51.5)
Proceeds from Sale of Assets	0.0	1.4
Cash for Investing Activities	(56.5)	(45.7)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	23.7	2.1
Changes in Notes Payable	0.5	(0.5)
Reductions of Long-term Debt	(1.4)	(1.0)
Dividends on Common Stock	(17.7)	(16.2)
Cash from (for) Financing Activities	5.1	(15.6)
Change in Cash and Cash Equivalents	17.1	7.8
Cash and Cash Equivalents at Beginning of Period	101.1	44.9
Cash and Cash Equivalents at End of Period	$ 118.2	$ 52.7

Operations and Significant Accounting Policies

3 Months Ended

Mar. 31, 2012

Operations and Significant Accounting Policies [Abstract]

Operations and Significant 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, 2012	December 31, 2011
Millions
Fuel	$31.8	$28.6
Materials and Supplies	40.4	40.5
Total Inventories	$72.2	$69.1



Prepayments and Other Current Assets	March 31, 2012	December 31, 2011
Millions
Deferred Fuel Adjustment Clause	$15.5	$17.5
Other	7.4	9.6
Total Prepayments and Other Current Assets	$22.9	$27.1



Other Current Liabilities	March 31, 2012	December 31, 2011
Millions
Customer Deposits	$21.3	$16.3
Other	20.5	29.3
Total Other Current Liabilities	$41.8	$45.6



Other Non-Current Liabilities	March 31, 2012	December 31, 2011
Millions
Asset Retirement Obligation	$60.2	$57.0
Other	50.9	48.1
Total Other Non-Current Liabilities	$111.1	$105.1

Supplemental Statement of Cash Flows Information.



For the Three Months Ended March 31,	2012	2011
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$12.3	$10.4
Cash Paid During the Period for Income Taxes	$0.2	$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(12.3)	$(14.4)
AFUDC – Equity	$0.8	$0.6

Accounts Receivable. Accounts receivable are reported on the consolidated balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses. In the third quarter of 2011, one of Minnesota Power’s Large Power Customers, NewPage Corporation, filed for Chapter 11 bankruptcy protection. Minnesota Power had a pre-bankruptcy petition receivable of $3.2 million as of March 31, 2012. Based on our assessment of the facts and circumstances existing as of March 31, 2012, we have determined that it is not probable that the pre-petition receivable has been impaired at this time. We will continue to assess for impairment as the bankruptcy proceeds and as facts and circumstances change. This customer’s operations have continued without interruption and we continue to provide electric and steam service to this customer. We have received payment of scheduled post-petition receivable balances and we expect continued payment of all other post-petition receivables.

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.

Fair Value. In May 2011, the FASB issued an accounting standards update on fair value measurement. This update requires disclosure of a sensitivity analysis for fair value measurements within Level 3 and the valuation process used. No retrospective application of this guidance is required. If we utilize Level 3 fair value measurements in the future, this guidance would significantly increase our disclosures in this area. This guidance is effective beginning with the quarter ended March 31, 2012, and did not have a material impact on our consolidated financial position, results of operations or cash flows.

Statement of Comprehensive Income. In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. This guidance is effective beginning with the quarter ended March 31, 2012, and modified our presentation of other comprehensive income, moving it from the footnotes to the face of the financial statements in a separate statement of comprehensive income immediately following the Consolidated Statement of Income. The components of net income and other comprehensive income are unchanged and earnings per share continues to be based on net income.

Business Segments

3 Months Ended

Mar. 31, 2012

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 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, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes a small amount of non-rate base generation, approximately 5,500 acres of land available-for-sale in Minnesota, and earnings on cash and investments.



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2012
Operating Revenue	$240.0			$218.6			$21.4
Fuel and Purchased Power Expense	77.1			77.1			—
Operating and Maintenance Expense	99.9			78.1			21.8
Depreciation Expense	24.6			23.2			1.4
Operating Income (Loss)	38.4			40.2			(1.8		)
Interest Expense	(11.0		)	(9.6		)	(1.4		)
Equity Earnings in ATC	4.6			4.6			—
Other Income (Loss)	0.7			0.8			(0.1		)
Income (Loss) Before Non-Controlling Interest and Income Taxes	32.7			36.0			(3.3		)
Income Tax Expense (Benefit)	8.3			11.6			(3.3		)
Net Income	24.4			24.4			—
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE	$24.4			$24.4			—

As of March 31, 2012
Total Assets		$2,906.6			$2,586.4			$320.2
Property, Plant and Equipment – Net		$2,002.8			$1,945.6			$57.2
Accumulated Depreciation		$1,099.0			$1,045.9			$53.1
Capital Additions		$39.7			$38.7			$1.0



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2011
Operating Revenue	$242.2			$223.0			$19.2
Fuel and Purchased Power Expense	79.0			79.0			—
Operating and Maintenance Expense	90.1			71.2			18.9
Depreciation Expense	22.3			21.2			1.1
Operating Income (Loss)	50.8			51.6			(0.8		)
Interest Expense	(10.7		)	(8.6		)	(2.1		)
Equity Earnings in ATC	4.4			4.4			—
Other Income	0.8			0.6			0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	45.3			48.0			(2.7		)
Income Tax Expense (Benefit)	8.2			9.6			(1.4		)
Net Income (Loss)	37.1			38.4			(1.3		)
Less: Non-Controlling Interest in Subsidiaries	(0.1		)	—			(0.1		)
Net Income (Loss) Attributable to ALLETE	$37.2			$38.4			$(1.2)

As of March 31, 2011
Total Assets		$2,613.4			$2,381.8			$231.6
Property, Plant and Equipment – Net		$1,841.3			$1,794.6			$46.7
Accumulated Depreciation		$1,043.4			$993.1			$50.3
Capital Additions		$35.9			$33.0			$2.9

- Definition

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

+ References

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-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Investments

3 Months Ended

Mar. 31, 2012

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. Our long-term investment portfolio includes the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits and land available-for-sale in Minnesota.



Investments	March 31, 2012	December 31, 2011
Millions
ALLETE Properties	$91.3	$91.3
Available-for-sale Securities	27.7	24.7
Other	16.7	16.3
Total Investments	$135.7	$132.3



ALLETE Properties	March 31, 2012	December 31, 2011
Millions
Land Inventory Beginning Balance (January 1, 2012 and 2011, respectively)	$86.0	$86.0
Deeds to Collateralized Property	—	1.8
Land Impairment	—	(1.7	)
Capitalized Improvements and Other	0.1	0.2
Cost of Real Estate Sold	—	(0.3	)
Land Inventory Ending Balance	86.1	86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	2.0	2.0
Other	3.2	3.3
Total Real Estate Assets	$91.3	$91.3

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, 2012 ($1.7 million as of December 31, 2011). In the fourth quarter of 2011, an impairment analysis of estimated future undiscounted cash flows was conducted and indicated that the cash flows were not adequate to recover the carrying basis of certain properties not strategic to our three major development projects. Consequently, we reduced the cost basis to estimated fair value resulting in a pretax impairment charge of $1.7 million. Fair value was determined based on property tax assessed values, discounted cash flow analysis, or a combination thereof.

Long-Term Finance Receivables. As of March 31, 2012, long-term finance receivables were $2.0 million net of allowance ($2.0 million net of allowance as of December 31, 2011). 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, 2012, we had allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2011).

Derivatives	3 Months Ended
Derivatives	Mar. 31, 2012
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 9 percent of the Company's outstanding long-term debt as of March 31, 2012. (See Note 8. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the quarter ended March 31, 2012. The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the consolidated balance sheet. As of March 31, 2012, a $0.6 million decrease (a $0.4 million decrease as of December 31, 2011) in fair value has been recorded and is included in other non-current liabilities on the consolidated balance sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the consolidated statement of cash flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the consolidated statement of income.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Fair Value

3 Months Ended

Mar. 31, 2012

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 9. Fair Value to the consolidated financial statements in our 2011 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, 2012 and December 31, 2011. 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 fair value assets and liabilities and their placement within the fair value hierarchy levels.



	Fair Value as of March 31, 2012
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities	$19.5	—	—	$19.5
Available-for-sale Securities – Corporate Debt Securities	—	$8.6	—	8.6
Money Market Funds	12.3	—	—	12.3
Total Fair Value of Assets	$31.8	$8.6	—	$40.4

Liabilities:
Deferred Compensation	—	$14.6	—	$14.6
Derivatives – Interest Rate Swap	—	0.6	—	0.6
Total Fair Value of Liabilities	—	$15.2	—	$15.2

Total Net Fair Value of Assets (Liabilities)	$31.8	$(6.6)	—	$25.2



	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Equity Securities	$17.6		—		—	$17.6
Available-for-sale Securities – Corporate Debt Securities	—		$8.2		—	8.2
Money Market Funds	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2

Liabilities:
Deferred Compensation	—		$12.8		—	$12.8
Derivatives – Interest Rate Swap	—		0.4		—	0.4
Total Fair Value of Liabilities	—		$13.2		—	$13.2

Total Net Fair Value of Assets (Liabilities)	$29.0		$(5.0)		—	$24.0



Recurring Fair Value Measures Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2011 and 2010, respectively	—	$6.7
Redeemed During the Period (a)	—	(6.7	)
Balance as of March 31, 2012 and 2011, respectively	—	—


(a)	The remaining ARS were redeemed at carrying value on January 5, 2011.

The Company’s policy is to recognize transfers in and transfers out of a given hierarchy 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, 2012 and 2011, 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 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, 2012	$862.0	$960.2
December 31, 2011	$863.3	$966.4

- 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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

Regulatory Matters

3 Months Ended

Mar. 31, 2012

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 Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case with the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court. On February 14, 2012, the Minnesota Supreme Court granted the petition for review. We cannot predict the outcome at this time.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. Minnesota Power has formula-based contracts with the City of Nashwauk through June 30, 2024, and through June 30, 2019, with the remaining 15 Minnesota municipal customers and SWL&P. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (10.38 percent). The formula-based rate methodology also provides for a monthly and yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to June 30, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on December 31, 2011, this customer submitted a cancellation notice with termination effective on December 31, 2013.

2010 Wisconsin Rate Increase. SWL&P’s current retail rates are based on a 2010 PSCW retail rate order, effective January 1, 2011, that allowed for a 10.9 percent return on common equity.

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.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, PPACA was signed into law. One of the provisions changed the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and were required to reverse previously recorded tax benefits which resulted in a non-recurring charge to net income of $4.0 million in 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from PPACA. On May 24, 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million and a related regulatory asset of $5.0 million in the second quarter of 2011.

Pension. On December 22, 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. If our petition is successful, the impact would be deferred in a regulatory asset (or liability) for recovery (or refund) in the Company’s next general rate case. We cannot predict the outcome at this time.

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.



Regulatory Assets and Liabilities	March 31, 2012		December 31, 2011
Millions
Current Regulatory Assets (a)
Deferred Fuel		$15.5		$17.5
Total Current Regulatory Assets	15.5		17.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	287.4		292.8
Income Taxes	28.5		28.6
Asset Retirement Obligation	10.3		9.8
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	2.4		4.6
Other	5.7		5.1
Total Non-Current Regulatory Assets	339.3		345.9

Total Regulatory Assets		$354.8		$363.4

Non-Current Regulatory Liabilities
Income Taxes		$21.2		$21.9
Plant Removal Obligations	15.9		15.0
Other	8.2		6.6
Total Non-Current Regulatory Liabilities		$45.3		$43.5


(a)	Current regulatory assets are included in prepayments and other on the consolidated balance sheet.

Investment in ATC

3 Months Ended

Mar. 31, 2012

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, 2012, our equity investment in ATC was $100.5 million ($98.9 million at December 31, 2011). In the first quarter of 2012, we invested $0.8 million in ATC, and on April 30, 2012, we invested an additional $1.2 million. In total, we expect to invest approximately $3.0 million in 2012.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2011	$98.9
Cash Investments	0.8
Equity in ATC Earnings	4.6
Distributed ATC Earnings	(3.8	)
Equity Investment Balance as of March 31, 2012	$100.5

ATC’s summarized financial data for the quarters ended March 31, 2012 and 2011, is as follows:



	Quarter Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2012	2011
Millions
Revenue	$147.7	$139.6
Operating Expense	69.6	63.1
Other Expense	20.0	22.3
Net Income	$58.1	$54.2

ALLETE’s Equity in Net Income	$4.6	$4.4

- Definition

The entire disclosure for equity investment, or group of investments, for which combined disclosure is appropriate, including: (a) the name of each investee and percentage of ownership of common stock, (b) accounting policies for investments in common stock, (c) difference between the amount at which the investment is carried and the amount of underlying equity in net assets and the accounting treatment of the difference, (d) the total fair value of each identified investment for which a market value is available, (e) summarized information as to assets, liabilities, and results of operations of the investees (for investments in unconsolidated subsidiaries, common stock of joint ventures, or other investments using the equity method), and (f) material effects of possible conversions, exercises, or contingent issuances of the investee. Other disclosures include (a) the names of any investee in which the investor owns 20 percent or more of the voting stock and investment is not accounted for using the equity method, and the reasons why not, and (b) the names of any investee in which the investor owns less than 20 percent of the voting stock and the investment is accounted for using the equity method, and the reasons why it is.

+ References + Details

Short-Term and Long-Term Debt	3 Months Ended
Short-Term and Long-Term Debt	Mar. 31, 2012
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, 2012, total short-term debt outstanding was $7.1 million ($6.5 million as of December 31, 2011) and consisted of long-term debt due within one year and notes payable. Long-Term Debt. No long-term debt was issued in the first three months of 2012. As of March 31, 2012, total long-term debt outstanding was $856.5 million ($857.9 million as of December 31, 2011). 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, 2012, our ratio was approximately 0.43 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, 2012, 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.

+ References + Details

Other Income (Expense)

3 Months Ended

Mar. 31, 2012

Other Income (Expense) [Abstract]

Other Income (Expense) [Text Block]

OTHER INCOME (EXPENSE)



	Quarter Ended
	March 31,
	2012		2011
Millions
AFUDC – Equity	$0.8		$0.6
Investment and Other Income (Expense)	(0.1	)	0.2
Total Other Income	$0.7		$0.8

Income Tax Expense

3 Months Ended

Mar. 31, 2012

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended
	March 31,
	2012		2011
Millions
Current Tax Expense
Federal (a)	—		—
State (a)	—			$0.1
Total Current Tax Expense	—		0.1
Deferred Tax Expense (Benefit)
Federal (b)	$8.7		6.8
State (b)	(0.8	)	1.5
Change in Valuation Allowance (c)	0.6		—
Investment Tax Credit Amortization	(0.2	)	(0.2		)
Total Deferred Tax Expense	8.3		8.1
Total Income Tax Expense	$8.3		$8.2

(a)

For the quarter ended March 31, 2012, the federal and state current tax expense (benefit) of zero and zero, respectively, (zero and $0.1 million for the quarter ended March 31, 2011) is due to a net operating loss (NOL) which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010. The 2011 and 2012 federal and state NOLs will be carried forward to offset future taxable income.


(b)	The quarter ended March 31, 2011, includes a reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case.


(c)	The increase in valuation allowance in 2012 is from renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

NOTE 10. INCOME TAX EXPENSE (Continued)

For the quarter ended March 31, 2012, the effective tax rate was 25.4 percent (18.1 percent for the quarter ended March 31, 2011; excluding the non-recurring income tax benefit from the reversal of the deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, the effective tax rate for the quarter ended March 31, 2011, was 31.8 percent). The decrease (excluding the non-recurring item above) in the effective tax rate from March 31, 2011, was primarily due to increased renewable tax credits. 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, and in 2011, for the non-recurring item discussed above.

Uncertain Tax Positions. As of March 31, 2012, we had gross unrecognized tax benefits of $11.2 million. Of this total, $0.5 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.

ALLETE's IRS exam for tax years 2005 through 2009 is currently awaiting review at the IRS appeals office. If the IRS appeals process is completed during the next twelve months, substantially all of the unrecognized tax benefits as of March 31, 2012, could be reversed. The unrecognized tax benefits are primarily due to tax positions which are timing in nature.

- 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.

+ References

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

Earnings Per Share and Common Stock

3 Months Ended

Mar. 31, 2012

Earnings Per Share and Common Stock [Abstract]

Earnings Per Share and Common Stock [Text Block]

EARNINGS PER SHARE AND COMMON STOCK

The difference between basic and diluted earnings per share, if any, arises from outstanding stock options and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. For the quarters ended March 31, 2012 and 2011, 0.2 million and 0.4 million options, respectively, to purchase shares of common stock 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.



		2012					2011
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 Attributable to ALLETE	$24.4			$24.4		$37.2			$37.2
Common Shares	36.8	0.1	36.9		34.6		0.1	34.7
Earnings Per Share	$0.66		$0.66			$1.07			$1.07

Pension and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2012

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	2012		2011		2012		2011
Millions
For the Quarter Ended March 31,
Service Cost	$2.3		$1.9		$1.0		$1.0
Interest Cost	6.6		6.9		2.4		2.7
Expected Return on Plan Assets	(8.8	)	(8.7	)	(2.5	)	(2.4	)
Amortization of Prior Service Costs	0.1		0.1		(0.4	)	(0.4	)
Amortization of Net Loss	4.3		3.0		1.9		2.1
Net Periodic Benefit Expense	$4.5		$3.2		$2.4		$3.0

Employer Contributions. For the quarter ended March 31, 2012, no contributions were made to our defined benefit pension plan (no contributions for the quarter ended March 31, 2011). For the quarter ended March 31, 2012, no contributions were made to our other postretirement benefit plan ($10.9 million for the quarter ended March 31, 2011). We expect to contribute $1.0 million to our defined benefit pension plan in 2012, and we expect to contribute $13.9 million to our other postretirement benefit plan in 2012.

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provides guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide postretirement health benefits that include prescription drug benefits, which qualify for the federal subsidy under the Act. For the quarter ended March 31, 2012, we received $0.3 million in prescription drug reimbursements.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments, Guarantees and Contingencies [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

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

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the 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, 2012, Square Butte had total debt outstanding of $429.8 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the five years, 2012 through 2016, 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.

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.

No power will be sold under this agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 2013. 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 the ability to transmit additional wind generation on the DC transmission line.

Wind 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 prices. There are no fixed capacity charges and we only pay for energy as it is delivered to us.

Hydro PPAs. Minnesota Power has a PPA with Manitoba Hydro that expires in April 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.

Minnesota Power has a separate PPA with Manitoba Hydro to purchase surplus energy from May 2011 through April 2022. This energy-only transaction 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 March 2011, the MPUC approved this PPA with Manitoba Hydro.

In May 2011, Minnesota Power and Manitoba Hydro signed a long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and requires construction of additional transmission capacity between Manitoba and the U.S. 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. On January 26, 2012, the MPUC approved this PPA with Manitoba Hydro. In February 2012, Minnesota Power and Manitoba Hydro proposed construction of a 500 kV transmission line between Manitoba and Hibbing, Minnesota in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy, which is expected to be in service in 2020. Total project cost and cost allocations are still to be determined.

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.

Bison 1 is an 82 MW wind facility in North Dakota, which was completed in two phases. The first phase was completed in 2010, and the second phase was completed in January 2012. The project also included construction of a 22-mile, 230 kV transmission line. Bison 1 had a total project cost of $173.8 million. We expect to incur additional costs of $3.6 million through 2013, related to land restoration and completion of remaining associated upgrades for the 250 kV DC transmission line, of which $2.6 million was spent through March 31, 2012. The MPUC has approved current cost recovery for Bison 1 investments and expenditures, and current customer billing rates for Bison 1 are based on a November 3, 2011 MPUC order.

Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota which are expected to be completed by the end of 2012. Site preparation is currently underway for both projects and the total project costs for Bison 2 and Bison 3 are estimated to be approximately $160 million each, of which $40.3 million and $25.8 million, respectively, was spent through March 31, 2012. In September 2011, and November 2011, the MPUC approved Minnesota Power's petitions seeking current cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively. In August 2011, and October 2011, the NDPSC issued a Certificate of Site Compatibility for Bison 2 and Bison 3, respectively. We anticipate filing petitions with the MPUC in the first half of 2012 to establish customer billing rates for the approved cost recovery.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements which expire in 2013. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements for 2012 is $37.4 million, and for 2013 is $23.8 million. Our minimum annual payment obligations 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 million termination fee. We lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is $10.9 million in 2012, $11.1 million in 2013, $11.4 million in 2014, $11.2 million in 2015, $9.2 million in 2016 and $43.0 million thereafter.

Transmission. We are making 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 (by ourselves or in combination with others), and our investment in ATC.

Transmission Investments. We have an approved cost recovery rider in place for certain transmission expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, we filed an updated billing factor that includes additional transmission projects and expenses, which we expect to be approved in 2012.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

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, municipals 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 three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015, of which $33.5 million was spent through March 31, 2012 ($27.8 million as of December 31, 2011). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

In July 2010, the MPUC granted a route permit for the 28-mile 345 kV line between Monticello and St. Cloud. The project was completed and placed into service in December 2011. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process is underway. The entire 238-mile, 345 kV line from St. Cloud to Fargo is expected to be in service by 2015.

In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids line and construction for the 230 kV line project commenced in January 2011. The Leech Lake Band of Ojibwe (LLBO) subsequently requested the MPUC suspend or revoke the route permit and also served the CapX2020 owners with a complaint filed in Leech Lake Tribal Court asserting adjudicatory and regulatory authority over the project. The CapX2020 owners filed a request for declaratory judgment in the United States District Court for the District of Minnesota (District Court) that the project does not require LLBO consent to cross non-tribal land within the reservation. In June 2011, the federal judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The LLBO abandoned its motion to dismiss the declaratory action because the District Court’s injunction order had already dismissed the basis for the motion, namely, that the District Court did not have jurisdiction to hear the CapX2020 owners’ action. The parties are now proceeding with discovery and the CapX2020 owners do not anticipate any actions by the District Court until after the completion of discovery closes on May 31, 2012. The MPUC has taken no action in the matter in light of ongoing litigation in federal and tribal courts. The CapX2020 utilities are vigorously defending against the LLBO actions.

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 future restrictive environmental requirements 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 determine prominent power supply trends and impacts on customers. All coal-fired generating facilities could potentially be impacted, with the possibility that additional environmental control installations will be needed. At Laskin and Taconite Harbor, we will also be considering options such as remissioning, repowering and retirement.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 heavily 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. Square Butte, located in North Dakota, burns lignite coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NO_X technologies. At this time, 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 the Boswell Unit 4 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. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome of these discussions.

Resolution of the NOVs could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which went into effect in October 2011. The final rule replaced the EPA’s 2005 Clean Air Interstate Rule (CAIR). However, on December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a ruling staying implementation of the CSAPR, pending judicial review, and ordered that the CAIR remain in place while the CSAPR is stayed.

If the CSAPR is reinstated after judicial review, it will require states in the CSAPR region to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. These regulations do not directly require the installation of controls. Instead, they require facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would be allocated to facilities annually by the EPA and would also be able to 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. 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. In its final determination, the EPA listed Minnesota as a CSAPR-affected state based on new 24-hour fine particulate NAAQS analysis. While the CAIR remains in effect, Minnesota participation in the CAIR will continue to be stayed. It is uncertain if the CSAPR-related emission restrictions will become effective for Minnesota utilities.

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Our analysis, based on our expected generation rates, indicates that these emission reductions would satisfy Minnesota Power’s SO₂ and NO_X emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012. We will continue to evaluate our compliance strategy under CSAPR and, if any capital investments or allowance purchases are required, we would likely seek recovery of those costs. We are unable to predict any additional CSAPR compliance costs we might incur if CSAPR is reinstated.

Minnesota 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 regional haze rule, certain large stationary sources, put in place 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, which are subject to BART requirements.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was not filed at that time due to the United States Court of Appeals for the District of Columbia Circuit’s remand of CAIR. Subsequently, 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.

On December 30, 2011, the EPA published in the Federal Register a proposal to revise the regional haze rule. This proposal would approve the trading program in the CSAPR as an alternative to determining BART. If adopted, states in the CSAPR region could substitute participation in CSAPR for source-specific BART requirements for SO₂ and NO_Xemissions from power plants. On January 2, 2012, the MPCA submitted to the EPA a supplemental Minnesota regional haze SIP stating that it would rely on the CSAPR to satisfy BART requirements for SO₂ and NO_x for electric generating units.

On January 25, 2012, the EPA published in the Federal Register a proposal to approve the Minnesota SIP, including the supplemental Minnesota SIP. If the Minnesota SIP, the supplemental Minnesota SIP, and the EPA’s regional haze rule revisions are finalized as currently proposed, and the CSAPR rule is reinstated, then Minnesota Power does not foresee a need to make significant additional expenditures at Taconite Harbor Unit 3 to comply with the regional haze rule.

If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final promulgation deadline to bring Taconite Harbor Unit 3 into compliance with the regional haze rule requirements. It is uncertain what controls would ultimately be required at Taconite Harbor Unit 3 under this scenario.

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 on February 16, 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 188 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 February 2015. States have the authority to grant sources a one-year extension and the EPA is assessing other means for granting additional extensions when justified. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $300 million to $400 million through 2016. Some additional controls for complying with the rule at our remaining coal-fired generating units may be required, the costs of which cannot be estimated at this time.

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. A final rule based on the December 2011 proposal is expected in 2012. On January 9, 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. Major sources are expected to have three years to achieve compliance with the final rule. It is not known yet whether the final rule will establish new compliance deadlines. Costs for complying with the final rule cannot be estimated at this time.

Minnesota Mercury Emission Reduction Act. Under Minnesota law, a mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2015, with implementation no later than December 31, 2018. The applicable statute also calls for an evaluation of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’s customers. Until Minnesota Power files its mercury emission reduction plan for Boswell Unit 4, it must file an annual report updating the MPUC and other stakeholders on the status of emission reduction planning for Boswell Unit 4. The first such update was filed with the MPUC in June 2011.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Mercury emission limits have also been included in the recently finalized MATS rule. We anticipate that the emission reduction plan implemented to comply with the MATS rule will satisfy the mercury emission limits under Minnesota law. Costs for the Boswell Unit 4 emission reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule discussed above.

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 a 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 require. 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 announced that it is deferring revision of this standard until 2013.

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA established a more stringent 24-hour average fine particulate matter (PM_2.5) standard and kept the annual average fine particulate matter standard and the 24-hour coarse particulate matter standard unchanged. The United States Court of Appeals for the District of Columbia Circuit has remanded the PM_2.5 standard to the EPA, requiring consideration of lower annual average standard values. The EPA expects to propose the new PM_2.5 standards in June 2012 with a goal to finalize the rule by June 2013. State attainment status determination will occur after the rule is finalized. It is not known when affected sources would have to take additional control measures if modeling demonstrates non-compliance at their property boundary. The EPA has indicated that ambient air quality monitoring for 2008 through 2010 will be used as a basis for states to characterize their attainment status.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized new 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 SO₂NAAQS also require the EPA to evaluate modeling data to determine attainment. The EPA notified states that their SIPs for attainment of the standard will be required to be submitted to the EPA for approval by June 2013. One-hour NAAQS attainment will be required by 2017.

The MPCA initiated modeling activities that included 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year.However, on April 12, 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, in which 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. The costs for complying with the final standard cannot be estimated at this time.

Climate Change. The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:


•	Expand our renewable energy supply;


•	Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies;


•	Provide energy conservation initiatives for our customers and engage in other demand side efforts; and


•	Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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, at existing facilities that undergo major modifications and at 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 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.

On March 28, 2012, the EPA announced its proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The new NSPS applies only to new or re-powered units. It is anticipated that the EPA will issue NSPS for existing fossil fuel-fired generating units in the future. We cannot predict what CO₂ control measures, if any, may be required by such NSPS.

Legal challenges to the EPA’s regulation of GHG emissions, including the Tailoring Rule, have been filed by others and are awaiting judicial determination. Comments to the permitting guidance were also submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

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.

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 published in the Federal Register 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. The EPA is obligated to finalize the rule by July 27, 2012. 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.

EPA Steam Electric Power Generating Effluent Guidelines. In late 2009, the EPA announced that it will be reviewing and reissuing the federal effluent guidelines for steam electric stations. These are the underlying federal water discharge rules that apply to all steam electric stations. The EPA has indicated that the new rule promulgating these guidelines will be proposed in 2012 and finalized in 2014. As part of the review phase for this new rule, the EPA issued an Information Collection Request (ICR) in June 2010, to most thermal electric generating stations in the country, including all five of Minnesota Power’s generating stations. The ICR was completed and submitted to the EPA in September 2010 for Boswell, Laskin, Taconite Harbor, Hibbard, and Rapids Energy Center. The ICR was designed to gather extensive information on the nature and extent of all water discharge and related wastewater handling at power plants. The information gathered through the ICR will form a basis for development of the eventual new rule, which could include more restrictive requirements on wastewater discharge, flue gas desulfurization, and wet ash handling operations. We are unable to predict the costs we might incur to comply with potential future water discharge regulations at this time.

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 13. 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. Comments on the proposed rule were due in November 2010. It is estimated that the final rule will be published in late 2012 or early 2013. We are unable to predict the compliance cost 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.

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site in the City of Superior, Wisconsin, and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. As of March 31, 2012, we have a $0.5 million liability for this site and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.

Other Matters

BNI Coal. As of March 31, 2012, BNI Coal had surety bonds outstanding of $29.8 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 currently estimated at $32.4 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

ALLETE Properties. As of March 31, 2012, 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 in various projects. The estimated cost of the remaining development work is approximately $7.4 million, of which $0.5 million is the contractual obligation of land purchasers. ALLETE Properties does not believe it is likely that any of these outstanding 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 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, 2012, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2011) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2011). At these ownership levels, our annual assessments are approximately $1.5 million for Town Center and $2.2 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. Under accounting guidance, these bonds are not reflected as debt on our consolidated balance sheet.

Legal Proceedings. 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 $20.0 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of March 31, 2012, because a potential loss is not currently probable or reasonable estimable; however, the Company believes it has adequate insurance coverage for any potential loss.

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, compliance with regulations, rate base and cost of service issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these matters are expected to materially change our present liquidity position, or have a material adverse effect on our financial condition.

Operations and Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2012
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.
Accounts Receivable [Policy Text Block]	Accounts receivable are reported on the consolidated balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses.
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.

- Definition

Disclosure of accounting policy for major classes of inventories, bases of stating inventories (for example, lower of cost or market), methods by which amounts are added and removed from inventory classes (for example, FIFO, LIFO, or average cost), loss recognition on impairment of inventories, and situations in which inventories are stated above cost. If inventory is carried at cost, this disclosure includes the nature of the cost elements included in inventory.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 6
-Subparagraph a
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 3
-Section A
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 81-1
-Paragraph 69-75
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher SEC
-Name Financial Reporting Release (FRR)
-Number 206
-Chapter 2
-Paragraph b
-Subparagraph i, ii

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-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 4
-Paragraph 3, 5-10, 15, 16, 17
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-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
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-Paragraph 3
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-Name Accounting Standards Codification
-Topic 210
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-Paragraph 1
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-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.6(b))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

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+ Details

- Definition

Disclosure of accounting policy for trade and other accounts receivable, and finance, loan and lease receivables, including those classified as held for investment and held for sale. This disclosure may include (1) the basis at which such receivables are carried in the entity's statements of financial position (2) how the level of the valuation allowance for receivables is determined (3) when impairments, charge-offs or recoveries are recognized for such receivables (4) the treatment of origination fees and costs, including the amortization method for net deferred fees or costs (5) the treatment of any premiums or discounts or unearned income (6) the entity's income recognition policies for such receivables, including those that are impaired, past due or placed on nonaccrual status and (7) the treatment of foreclosures or repossessions (8) the nature and amount of any guarantees to repurchase receivables.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 114
-Paragraph 20
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Name Emerging Issues Task Force (EITF)
-Number 92-5
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Position (SOP)
-Number 01-6
-Paragraph 13
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-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 3-5
-Article 5

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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/subtopic&trid=2196816

+ Details

Investments (Policies)	3 Months Ended
Investments (Policies)	Mar. 31, 2012
Investments [Abstract]
Land Held-for-sale [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.
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.

- Definition

Disclosure of accounting policy for those finance, loan and lease receivables classified as held for investment. This disclosure may include (1) the basis at which such receivables are carried in the entity's statements of financial position (2) how the level of the allowance for loan and lease losses is determined (3) when impairments, charge-offs or recoveries are recognized for such receivables (4) the treatment of commitment and other fees and loan origination costs (including, if applicable, how the entity accounts for fees and costs associated with credit cards that are either purchased or originated) (5) the treatment of any premiums or discounts or unearned income (6) the entity's income recognition policies for such receivables, including those that are impaired, past due or placed on nonaccrual status (for impaired loans, the policy for recognizing interest income on such loans, including how cash receipts are recorded) and (7) the treatment of foreclosures or repossessions.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 21
-Paragraph 16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 114
-Paragraph 20
-Subparagraph b
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 92-5
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 01-6
-Paragraph 13
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 3-5
-Article 5

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 91
-Paragraph 5-14, 22
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+ Details

Derivatives (Policies)	3 Months Ended
Derivatives (Policies)	Mar. 31, 2012
Derivatives [Abstract]
Derivatives [Policy Text Block]	Cash flows from derivative activities are presented in the same category as the item being hedged on the consolidated statement of cash flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the consolidated statement of income.

- Definition

Disclosure of accounting policy for its derivative instruments and hedging activities. Disclosure may include: (1) Each method used to account for derivative financial instruments and derivative commodity instruments ("derivatives"); (2) the types of derivatives accounted for under each method; (3) the criteria required to be met for each accounting method used, including a discussion of the criteria required to be met for hedge or deferral accounting and accrual or settlement accounting (for example, whether and how risk reduction, correlation, designation, and effectiveness tests are applied); (4) the accounting method used if the criteria specified for hedge accounting are not met; (5) the method used to account for termination of derivatives designated as hedges or derivatives used to affect directly or indirectly the terms, fair values, or cash flows of a designated item; (6) the method used to account for derivatives when the designated item matures, is sold, is extinguished, or is terminated. In addition, the method used to account for derivatives designated to an anticipated transaction, when the anticipated transaction is no longer likely to occur; and (7) where and when derivatives, and their related gains or losses are reported in the statement of financial position, cash flows, and results of operations and (8) an accounting policy decision to offset fair value amounts with counterparties. An entity may also describe its embedded derivatives, and the method(s) used to determine the fair values of derivatives and any significant assumptions used in such valuations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph n
-Article 4

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 39
-Paragraph 10
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-Name Accounting Standards Codification
-Topic 815
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+ Details

Fair Value (Policies)	3 Months Ended
Fair Value (Policies)	Mar. 31, 2012
Fair Value [Abstract]
Fair Value Transfers [Policy Text Block]	The Company’s policy is to recognize transfers in and transfers out of a given hierarchy level as of the actual date of the event or of the change in circumstances that caused the transfer.
Fair Value of Financial Instruments [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. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The fair value for the item listed below was based on quoted market prices for the same or similar instruments (Level 2).

Regulatory Matters (Policies)	3 Months Ended
Regulatory Matters (Policies)	Mar. 31, 2012
Regulatory Matters [Abstract]
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.

- Definition

Disclosure of accounting policy for public utilities. Examples include a discussion about the scope criteria and appropriateness for and extent of the application of generally accepted accounting principles related to accounting for the effects of certain types of regulation (may include identification of specific business units). Other examples of the disclosures may include: descriptions of the form and economic effects of regulation (for example, but not limited to, recording of regulatory assets and liabilities to the rate setting process); statement about periodic assessments of periodic assessments of generally accepted accounting principles related to accounting for the effects of certain types of regulation; information regarding amortization of and return on regulatory assets and liabilities, including the remaining amounts and recovery or settlement periods; accounting for changes to recovery estimates; AFUDC, plant abandonment's and plant disallowances.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 71
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 92
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 101
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 980
-SubTopic 10
-URI http://asc.fasb.org/subtopic&trid=2156579

+ Details

Investment in ATC Investment in ATC (Policies)	3 Months Ended
Investment in ATC Investment in ATC (Policies)	Mar. 31, 2012
Investment in ATC [Abstract]
Equity Method Investment [Policy Text Block]	We account for our investment in ATC under the equity method of accounting.

- Definition

Disclosure of accounting policy for the equity method of accounting for investments in common stock or other interests including unconsolidated subsidiaries, corporate joint ventures, noncontrolling interests in real estate ventures, limited partnerships, and limited liability companies. The accounting policy may include information such as: (1) initially recording an investment in the stock of an investee at cost; (2) adjusting the carrying amount of the investment to recognize the investor's share of the earnings or losses of the investee after the date of acquisition; and (3) adjustments to reflect the investor's share of changes in the investee's capital (dividends). This disclosure may also include a detailed description of the policy for determining the amount of equity method losses recognized after an investment has been reduced to zero as a result of previous losses, reasons for not using the equity method when the investor company owns 20 percent or more of the voting stock of the investee's company (including identification of the significant investee), reasons for using the equity method when the ownership percentage is less than 20 percent, and discussion of recognition of equity method losses when an investor's total investment in an investee includes, in addition to an investment in common stock, other investments such as preferred stock and loans to the investee. An entity also may describe how such investments are assessed for impairment.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 12
-Article 5

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
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-Name Accounting Principles Board Opinion (APB)
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-Name Emerging Issues Task Force (EITF)
-Number 02-14
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-Number 03-16
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-Name Emerging Issues Task Force (EITF)
-Number 98-13
-Paragraph 5, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 99-10
-Paragraph 6, 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-46
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.12)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-URI http://asc.fasb.org/subtopic&trid=2196966

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (a)(2)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

+ Details

Commitments, Guarantees and Contingencies (Policies)	3 Months Ended
Commitments, Guarantees and Contingencies (Policies)	Mar. 31, 2012
Commitments, Guarantees and Contingencies [Abstract]
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.

- Definition

Disclosure of accounting policy for obligations that resulted from improper or other-than normal operation of a long-lived asset in the past. This accounting policy may address (1) whether the related remediation costs are expensed or capitalized, (2) whether the obligation is measured on a discounted basis, (3) the event, situation, or set of circumstances that generally triggers recognition of loss contingencies arising from the entity's environmental remediation-related obligations, and (4) the timing of recognition of any recoveries.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 96-1
-Paragraph 99, 100, 101, 147, 148, 149, 150, 152, 153, 154
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 89-13
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 90-8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6393242&loc=d3e13231-110859

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 55
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=6571209&loc=d3e13669-110860

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-URI http://asc.fasb.org/subtopic&trid=2175709

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6393242&loc=d3e13185-110859

+ Details

Operations and Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2012

Operations and Significant Accounting Policies [Abstract]

Inventories [Table Text Block]



Inventories	March 31, 2012	December 31, 2011
Millions
Fuel	$31.8	$28.6
Materials and Supplies	40.4	40.5
Total Inventories	$72.2	$69.1

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	March 31, 2012	December 31, 2011
Millions
Deferred Fuel Adjustment Clause	$15.5	$17.5
Other	7.4	9.6
Total Prepayments and Other Current Assets	$22.9	$27.1

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



Other Current Liabilities	March 31, 2012	December 31, 2011
Millions
Customer Deposits	$21.3	$16.3
Other	20.5	29.3
Total Other Current Liabilities	$41.8	$45.6



Other Non-Current Liabilities	March 31, 2012	December 31, 2011
Millions
Asset Retirement Obligation	$60.2	$57.0
Other	50.9	48.1
Total Other Non-Current Liabilities	$111.1	$105.1

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



For the Three Months Ended March 31,	2012	2011
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$12.3	$10.4
Cash Paid During the Period for Income Taxes	$0.2	$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(12.3)	$(14.4)
AFUDC – Equity	$0.8	$0.6

Business Segments (Tables)

3 Months Ended

Mar. 31, 2012

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2012
Operating Revenue	$240.0			$218.6			$21.4
Fuel and Purchased Power Expense	77.1			77.1			—
Operating and Maintenance Expense	99.9			78.1			21.8
Depreciation Expense	24.6			23.2			1.4
Operating Income (Loss)	38.4			40.2			(1.8		)
Interest Expense	(11.0		)	(9.6		)	(1.4		)
Equity Earnings in ATC	4.6			4.6			—
Other Income (Loss)	0.7			0.8			(0.1		)
Income (Loss) Before Non-Controlling Interest and Income Taxes	32.7			36.0			(3.3		)
Income Tax Expense (Benefit)	8.3			11.6			(3.3		)
Net Income	24.4			24.4			—
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE	$24.4			$24.4			—

As of March 31, 2012
Total Assets		$2,906.6			$2,586.4			$320.2
Property, Plant and Equipment – Net		$2,002.8			$1,945.6			$57.2
Accumulated Depreciation		$1,099.0			$1,045.9			$53.1
Capital Additions		$39.7			$38.7			$1.0



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended March 31, 2011
Operating Revenue	$242.2			$223.0			$19.2
Fuel and Purchased Power Expense	79.0			79.0			—
Operating and Maintenance Expense	90.1			71.2			18.9
Depreciation Expense	22.3			21.2			1.1
Operating Income (Loss)	50.8			51.6			(0.8		)
Interest Expense	(10.7		)	(8.6		)	(2.1		)
Equity Earnings in ATC	4.4			4.4			—
Other Income	0.8			0.6			0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	45.3			48.0			(2.7		)
Income Tax Expense (Benefit)	8.2			9.6			(1.4		)
Net Income (Loss)	37.1			38.4			(1.3		)
Less: Non-Controlling Interest in Subsidiaries	(0.1		)	—			(0.1		)
Net Income (Loss) Attributable to ALLETE	$37.2			$38.4			$(1.2)

As of March 31, 2011
Total Assets		$2,613.4			$2,381.8			$231.6
Property, Plant and Equipment – Net		$1,841.3			$1,794.6			$46.7
Accumulated Depreciation		$1,043.4			$993.1			$50.3
Capital Additions		$35.9			$33.0			$2.9

- 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, 2012

Investments [Abstract]

Long-Term Investment Portfolio [Table Text Block]



Investments	March 31, 2012	December 31, 2011
Millions
ALLETE Properties	$91.3	$91.3
Available-for-sale Securities	27.7	24.7
Other	16.7	16.3
Total Investments	$135.7	$132.3



ALLETE Properties	March 31, 2012	December 31, 2011
Millions
Land Inventory Beginning Balance (January 1, 2012 and 2011, respectively)	$86.0	$86.0
Deeds to Collateralized Property	—	1.8
Land Impairment	—	(1.7	)
Capitalized Improvements and Other	0.1	0.2
Cost of Real Estate Sold	—	(0.3	)
Land Inventory Ending Balance	86.1	86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	2.0	2.0
Other	3.2	3.3
Total Real Estate Assets	$91.3	$91.3

Fair Value (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of March 31, 2012
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities	$19.5	—	—	$19.5
Available-for-sale Securities – Corporate Debt Securities	—	$8.6	—	8.6
Money Market Funds	12.3	—	—	12.3
Total Fair Value of Assets	$31.8	$8.6	—	$40.4

Liabilities:
Deferred Compensation	—	$14.6	—	$14.6
Derivatives – Interest Rate Swap	—	0.6	—	0.6
Total Fair Value of Liabilities	—	$15.2	—	$15.2

Total Net Fair Value of Assets (Liabilities)	$31.8	$(6.6)	—	$25.2



	Fair Value as of December 31, 2011
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Equity Securities	$17.6		—		—	$17.6
Available-for-sale Securities – Corporate Debt Securities	—		$8.2		—	8.2
Money Market Funds	11.4		—		—	11.4
Total Fair Value of Assets		$29.0		$8.2	—		$37.2

Liabilities:
Deferred Compensation	—		$12.8		—	$12.8
Derivatives – Interest Rate Swap	—		0.4		—	0.4
Total Fair Value of Liabilities	—		$13.2		—	$13.2

Total Net Fair Value of Assets (Liabilities)	$29.0		$(5.0)		—	$24.0

Recurring Fair Value Measures - Activity in Level 3 [Table Text Block]



Recurring Fair Value Measures Activity in Level 3	Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2011 and 2010, respectively	—	$6.7
Redeemed During the Period (a)	—	(6.7	)
Balance as of March 31, 2012 and 2011, respectively	—	—


(a)	The remaining ARS were redeemed at carrying value on January 5, 2011.

Fair Value of Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
March 31, 2012	$862.0	$960.2
December 31, 2011	$863.3	$966.4

- Definition

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income, and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issuances, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References + Details

- Definition

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13433-108611

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13467-108611

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13476-108611

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19207-110258

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

+ Details

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2012

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	March 31, 2012		December 31, 2011
Millions
Current Regulatory Assets (a)
Deferred Fuel		$15.5		$17.5
Total Current Regulatory Assets	15.5		17.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	287.4		292.8
Income Taxes	28.5		28.6
Asset Retirement Obligation	10.3		9.8
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	2.4		4.6
Other	5.7		5.1
Total Non-Current Regulatory Assets	339.3		345.9

Total Regulatory Assets		$354.8		$363.4

Non-Current Regulatory Liabilities
Income Taxes		$21.2		$21.9
Plant Removal Obligations	15.9		15.0
Other	8.2		6.6
Total Non-Current Regulatory Liabilities		$45.3		$43.5


(a)	Current regulatory assets are included in prepayments and other on the consolidated balance sheet.

Investment in ATC (Tables)

3 Months Ended

Mar. 31, 2012

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, 2011	$98.9
Cash Investments	0.8
Equity in ATC Earnings	4.6
Distributed ATC Earnings	(3.8	)
Equity Investment Balance as of March 31, 2012	$100.5

ATC Summarized Financial Data [Table Text Block]

ATC’s summarized financial data for the quarters ended March 31, 2012 and 2011, is as follows:



	Quarter Ended
ATC Summarized Financial Data	March 31,
Income Statement Data	2012	2011
Millions
Revenue	$147.7	$139.6
Operating Expense	69.6	63.1
Other Expense	20.0	22.3
Net Income	$58.1	$54.2

ALLETE’s Equity in Net Income	$4.6	$4.4

Other Income (Expense) (Tables)

3 Months Ended

Mar. 31, 2012

Other Income (Expense) [Abstract]

Other Income (Expense) [Table Text Block]



	Quarter Ended
	March 31,
	2012		2011
Millions
AFUDC – Equity	$0.8		$0.6
Investment and Other Income (Expense)	(0.1	)	0.2
Total Other Income	$0.7		$0.8

Income Tax Expense (Tables)

3 Months Ended

Mar. 31, 2012

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended
	March 31,
	2012		2011
Millions
Current Tax Expense
Federal (a)	—		—
State (a)	—			$0.1
Total Current Tax Expense	—		0.1
Deferred Tax Expense (Benefit)
Federal (b)	$8.7		6.8
State (b)	(0.8	)	1.5
Change in Valuation Allowance (c)	0.6		—
Investment Tax Credit Amortization	(0.2	)	(0.2		)
Total Deferred Tax Expense	8.3		8.1
Total Income Tax Expense	$8.3		$8.2

(a)


(b)	The quarter ended March 31, 2011, includes a reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case.


(c)	The increase in valuation allowance in 2012 is from renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

Earnings Per Share and Common Stock (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share and Common Stock [Abstract]

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



		2012					2011
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 Attributable to ALLETE	$24.4			$24.4		$37.2			$37.2
Common Shares	36.8	0.1	36.9		34.6		0.1	34.7
Earnings Per Share	$0.66		$0.66			$1.07			$1.07

Pension and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2012

Pension and Other Postretirement Benefit Plans [Abstract]

Components of Net Periodic Benefit Expense [Table Text Block]



	Pension				Other Postretirement
Components of Net Periodic Benefit Expense	2012		2011		2012		2011
Millions
For the Quarter Ended March 31,
Service Cost	$2.3		$1.9		$1.0		$1.0
Interest Cost	6.6		6.9		2.4		2.7
Expected Return on Plan Assets	(8.8	)	(8.7	)	(2.5	)	(2.4	)
Amortization of Prior Service Costs	0.1		0.1		(0.4	)	(0.4	)
Amortization of Net Loss	4.3		3.0		1.9		2.1
Net Periodic Benefit Expense	$4.5		$3.2		$2.4		$3.0

- Definition

Tabular disclosure of one or more of the entity's defined benefit pension plans or one or more other defined benefit postretirement plans, separately for pension plans and other postretirement benefit plans including the entity's schedule of fair value of plan assets for defined benefit or other postretirement plans.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 4, 7, 16, 20, 21
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e1928-114920

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=6930749&loc=d3e4179-114921

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2410-114920

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2439-114920

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2417-114920

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Operations and Significant Accounting Policies (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Inventories [Abstract]
Fuel	$ 31.8		$ 28.6
Materials and Supplies	40.4		40.5
Total Inventories	72.2		69.1
Prepayments and Other Current Assets [Abstract]
Deferred Fuel Adjustment Clause	15.5		17.5
Other	7.4		9.6
Total Prepayments and Other Current Assets	22.9		27.1
Other Current Liabilites [Abstract]
Customer Deposits	21.3		16.3
Other	20.5		29.3
Total Other Current Liabilities	41.8		45.6
Other Non-Current Liabilities [Abstract]
Asset Retirement Obligation	60.2		57.0
Other	50.9		48.1
Total Other Non-Current Liabilities	111.1		$ 105.1
Supplemental Statement of Cash Flows Information [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized	12.3	$ 10.4
Cash Paid During the Period for Income Taxes	0.2	0.2
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	(12.3)	(14.4)
AFUDC - Equity	0.8	$ 0.6
Accounts Receivable [Abstract]
Pre-Bankruptcy Petition Receivable	$ 3.2

Business Segments (Details) $ in Millions	3 Months Ended
Business Segments (Details) $ in Millions	Mar. 31, 2012 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2011 USD ($)
Business Segments [Line Items]
Operating Revenue	$ 240.0	$ 242.2
Fuel and Purchased Power Expense	77.1	79.0
Operating and Maintenance Expense	99.9	90.1
Depreciation Expense	24.6	22.3
Operating Income (Loss)	38.4	50.8
Interest Expense	(11.0)	(10.7)
Equity Earnings in ATC	4.6	4.4
Other Income (Loss)	0.7	0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	32.7	45.3
Income Tax Expense (Benefit)	8.3	8.2
Net Income	24.4	37.1
Less: Non-Controlling Interest in Subsidiaries	0.0	(0.1)
Net Income Attributable to ALLETE	24.4	37.2
Total Assets	2,906.6	2,613.4	$ 2,876.0
Property, Plant and Equipment - Net	2,002.8	1,841.3	$ 1,982.7
Accumulated Depreciation	1,099.0	1,043.4
Capital Additions	39.7	35.9
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue	218.6	223.0
Fuel and Purchased Power Expense	77.1	79.0
Operating and Maintenance Expense	78.1	71.2
Depreciation Expense	23.2	21.2
Operating Income (Loss)	40.2	51.6
Interest Expense	(9.6)	(8.6)
Equity Earnings in ATC	4.6	4.4
Other Income (Loss)	0.8	0.6
Income (Loss) Before Non-Controlling Interest and Income Taxes	36.0	48.0
Income Tax Expense (Benefit)	11.6	9.6
Net Income	24.4	38.4
Less: Non-Controlling Interest in Subsidiaries	0.0	0.0
Net Income Attributable to ALLETE	24.4	38.4
Total Assets	2,586.4	2,381.8
Property, Plant and Equipment - Net	1,945.6	1,794.6
Accumulated Depreciation	1,045.9	993.1
Capital Additions	$ 38.7	33.0
Investments and Other [Member]
Business Segments [Line Items]
Number of acres of land available-for-sale in Minnesota	5,500
Operating Revenue	$ 21.4	19.2
Fuel and Purchased Power Expense	0.0	0.0
Operating and Maintenance Expense	21.8	18.9
Depreciation Expense	1.4	1.1
Operating Income (Loss)	(1.8)	(0.8)
Interest Expense	(1.4)	(2.1)
Equity Earnings in ATC	0.0	0.0
Other Income (Loss)	(0.1)	0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	(3.3)	(2.7)
Income Tax Expense (Benefit)	(3.3)	(1.4)
Net Income	0.0	(1.3)
Less: Non-Controlling Interest in Subsidiaries	0.0	(0.1)
Net Income Attributable to ALLETE	0.0	(1.2)
Total Assets	320.2	231.6
Property, Plant and Equipment - Net	57.2	46.7
Accumulated Depreciation	53.1	50.3
Capital Additions	$ 1.0	$ 2.9

Investments (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
Investments (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011	Dec. 31, 2011
Investments [Abstract]
ALLETE Properties	$ 91.3	$ 91.3	$ 91.3
Available-for-sale Securities	27.7	24.7	24.7
Other	16.7	16.3	16.3
Total Investments	135.7	132.3	132.3
ALLETE Properties [Rollforward]
Land Inventory Beginning Balance (January 1, 2012 and 2011, respectively)	86.0		86.0
Deeds to Collateralized Property	0.0		1.8
Land Impairment	0.0	1.7	(1.7)
Capitalized Improvements and Other	0.1		0.2
Cost of Real Estate Sold	0.0		(0.3)
Land Inventory Ending Balance	86.1	86.0	86.0
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	2.0	2.0	2.0
Other	3.2	3.3	3.3
Total Real Estate Assets	91.3	91.3	91.3
Long-Term Finance Receivables, Allowance	$ 0.6	$ 0.6	$ 0.6

Derivatives (Details) - USD ($) $ in Millions	3 Months Ended
Derivatives (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Derivatives [Line Items]
Debt Instrument, Face Amount	$ 75.0
Debt Instrument, Description of Variable Rate Basis	one-month LIBOR
Debt Instrument, Basis Spread on Variable Rate	1.00%
Description of Derivative Activity Volume	represents approximately 9 percent of the Company's outstanding long-term debt
Derivative, Description of Variable Rate Basis	one-month LIBOR
Derivative, Fixed Interest Rate	0.825%
Discussion of Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the quarter ended March 31, 2012.
Derivative, Interest Rate Swap Liability	$ 0.6	$ 0.4

Fair Value - Recurring Fair Value Measures (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Recurring Fair Value Measures [Abstract]
Derivatives - Interest Rate Swap	$ 0.6	$ 0.4
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Recurring Fair Value Measures [Abstract]
Equity Securities	19.5	17.6
Available-for-sale Securities - Corporate Debt Securities	0.0	0.0
Money Market Funds	12.3	11.4
Total Fair Value of Assets	31.8	29.0
Deferred Compensation	0.0	0.0
Derivatives - Interest Rate Swap	0.0	0.0
Total Fair Value of Liabilities	0.0	0.0
Total Net Fair Value of Assets (Liabilities)	31.8	29.0
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Recurring Fair Value Measures [Abstract]
Equity Securities	0.0	0.0
Available-for-sale Securities - Corporate Debt Securities	8.6	8.2
Money Market Funds	0.0	0.0
Total Fair Value of Assets	8.6	8.2
Deferred Compensation	14.6	12.8
Derivatives - Interest Rate Swap	0.6	0.4
Total Fair Value of Liabilities	15.2	13.2
Total Net Fair Value of Assets (Liabilities)	(6.6)	(5.0)
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Recurring Fair Value Measures [Abstract]
Equity Securities	0.0	0.0
Available-for-sale Securities - Corporate Debt Securities	0.0	0.0
Money Market Funds	0.0	0.0
Total Fair Value of Assets	0.0	0.0
Deferred Compensation	0.0	0.0
Derivatives - Interest Rate Swap	0.0	0.0
Total Fair Value of Liabilities	0.0	0.0
Total Net Fair Value of Assets (Liabilities)	0.0	0.0
Fair Value, Measurements, Recurring [Member] \| Total [Member]
Recurring Fair Value Measures [Abstract]
Equity Securities	19.5	17.6
Available-for-sale Securities - Corporate Debt Securities	8.6	8.2
Money Market Funds	12.3	11.4
Total Fair Value of Assets	40.4	37.2
Deferred Compensation	14.6	12.8
Derivatives - Interest Rate Swap	0.6	0.4
Total Fair Value of Liabilities	15.2	13.2
Total Net Fair Value of Assets (Liabilities)	$ 25.2	$ 24.0

Fair Value - Recurring Fair Value Measures, Activity in Level 3 (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Hierarchy Transfers, All Levels	$ 0.0
Debt Securities Issued by States of the United States (ARS) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of December 31, 2011 and 2010, respectively	0.0	$ 6.7
Redeemed During the Period	0.0	(6.7)
Balance as of March 31, 2012 and 2011, respectively	$ 0.0	$ 0.0

Fair Value - Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Fair Value [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 862.0	$ 863.3
Long-term Debt, Including Current Portion - Fair Value	$ 960.2	$ 966.4

Regulatory Matters (Details) $ in Millions	3 Months Ended
Regulatory Matters (Details) $ in Millions	Jun. 30, 2011 USD ($)	Mar. 31, 2010 USD ($)	Mar. 31, 2012 USD ($) Customers	Dec. 31, 2011 USD ($)	Jun. 01, 2011	Dec. 31, 2010
The Patient Protection and Affordable Care Act of 2010 (PPACA) [Abstract]
Non-Current Regulatory Assets			$ 339.3	$ 345.9
Medicare Part D [Member]
The Patient Protection and Affordable Care Act of 2010 (PPACA) [Abstract]
Non-Current Regulatory Assets			5.0	$ 5.0
Income Tax Benefit, MPUC Approval of Deferral of PPACA [Member]
Electric Rates [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions	$ 2.9
The Patient Protection and Affordable Care Act of 2010 (PPACA) [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions	$ 2.9
Income Tax Benefit, MPUC Approval of Deferral of PPACA [Member] \| Medicare Part D [Member]
The Patient Protection and Affordable Care Act of 2010 (PPACA) [Abstract]
Non-Current Regulatory Assets			$ 5.0
DTA Reversal, Elimination of Medicare Part D [Member]
Electric Rates [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions		$ 4.0
The Patient Protection and Affordable Care Act of 2010 (PPACA) [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions		$ 4.0
2010 MN Rate Case [Member]
Electric Rates [Abstract]
Approved Percentage of Capital Structure Related to Equity					54.29%
FERC-Approved Wholesale Rates [Member]
Electric Rates [Abstract]
Approved Rate of Return on Common Equity					10.38%
Non-Affiliated Municipal Customers, Municipalities \| Customers			16
Non-Affiliated Municipal Customers, Private Utilities \| Customers			1
Length of Notice Required to Terminate (Years)			3
Non-Affiliated Municipal Customers, Private Utilities [Member]
Electric Rates [Abstract]
Length of Notice Required to Terminate (Years)			2
2010 Wisconsin Rate Increase [Member]
Electric Rates [Abstract]
Approved Rate of Return on Common Equity						10.90%

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

Mar. 31, 2012

Dec. 31, 2011

Regulatory Assets [Line Items]

Current Regulatory Assets

$ 15.5

$ 17.5

Non-Current Regulatory Assets

339.3

345.9

Regulatory Assets

354.8

363.4

Deferred Fuel [Member]

Regulatory Assets [Line Items]

Current Regulatory Assets

^[1]

15.5

17.5

Future Benefit Obligations Under Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets [Line Items]

Non-Current Regulatory Assets

287.4

292.8

Income Taxes [Member]

Regulatory Assets [Line Items]

Non-Current Regulatory Assets

28.5

28.6

Asset Retirement Obligation [Member]

Regulatory Assets [Line Items]

Non-Current Regulatory Assets

10.3

9.8

PPACA Income Tax Deferral [Member]

Regulatory Assets [Line Items]

Non-Current Regulatory Assets

5.0

Conservation Improvement Program [Member]

Regulatory Assets [Line Items]

Non-Current Regulatory Assets

2.4

4.6

Other [Member]

Regulatory Assets [Line Items]

Non-Current Regulatory Assets

$ 5.7

$ 5.1

[1]	Current regulatory assets are included in prepayments and other on the consolidated balance sheet.

Regulatory Matters - Regulatory Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Regulatory Liabilities [Line Items]
Non-Current Regulatory Liabilties	$ 45.3	$ 43.5
Income Taxes [Member]
Regulatory Liabilities [Line Items]
Non-Current Regulatory Liabilties	21.2	21.9
Plant Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Non-Current Regulatory Liabilties	15.9	15.0
Other [Member]
Regulatory Liabilities [Line Items]
Non-Current Regulatory Liabilties	$ 8.2	$ 6.6

Investment in ATC (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
Investment in ATC (Details) - USD ($) $ in Millions	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2012	Apr. 30, 2012
Investment in ATC [Abstract]
Ownership Percentage	8.00%
Approved Return on Common Equity	12.20%
Equity Method Investment - Anticipated Investment for Year			$ 3.0
Equity Method Investment - Investments Made During Year	$ 0.8			$ 1.2
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2011	98.9		$ 98.9
Cash Investments	0.8
Equity Earnings in ATC	4.6	$ 4.4
Distributed ATC Earnings	(3.8)
Equity Investment Balance as of March 31, 2012	100.5
ATC Summarized Financial Data [Abstract]
Revenue	147.7	139.6
Operating Expense	69.6	63.1
Other Expense	20.0	22.3
Net Income	58.1	54.2
ALLETE's Equity in Net Income	$ 4.6	$ 4.4

Short-Term and Long-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Short-Term and Long-Term Debt [Abstract]
Short-Term Debt Outstanding	$ 7.1	$ 6.5
Long-Term Debt Outstanding	$ 856.5	$ 857.9
Debt Instrument, Required Indebtedness to Total Capital Ratio	0.65 to 1.00
Debt Instrument, Actual Indebtedness to Total Capital Ratio	0.43 to 1.00

Other Income (Expense) (Details) - USD ($) $ in Millions	3 Months Ended
Other Income (Expense) (Details) - USD ($) $ in Millions	Mar. 31, 2012	Mar. 31, 2011
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 0.8	$ 0.6
Investment and Other Income (Expense)	(0.1)	0.2
Total Other Income	$ 0.7	$ 0.8

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

3 Months Ended

Mar. 31, 2012

Mar. 31, 2011

Current Tax Expense [Abstract]

Current Tax Expense - Federal

^[1]

$ 0.0

Current Tax Expense - State

^[1]

0.0

0.1

Total Current Tax Expense

0.0

0.1

Deferred Tax Expense (Benefit) [Abstract]

Deferred Tax Expense - Federal

^[2]

8.7

6.8

Deferred Tax Expense (Benefit) - State

^[2]

(0.8)

1.5

Change in Valuation Allowance

^[3]

0.6

0.0

Investment Tax Credit Amortization

(0.2)

Total Deferred Tax Expense

8.3

8.1

Total Income Tax Expense

$ 8.3

$ 8.2

Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]

Effective Income Tax Rate, Continuing Operations

25.40%

18.10%

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate

41.00%

Uncertain Tax Positions [Abstract]

Unrecognized Tax Benefits

$ 11.2

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

$ 0.5

DTL Reversal, Revenue Receivable Forgone [Member]

Income Tax Expense, Unusual/Nonrecurring Items [Abstract]

Tax Adjustments, Settlements, and Unusual Provisions

$ 6.2

Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]

Effective Income Tax Rate Reconciliation, Other Adjustments

31.80%

[1]	For the quarter ended March 31, 2012, the federal and state current tax expense (benefit) of zero and zero, respectively, (zero and $0.1 million for the quarter ended March 31, 2011) is due to a net operating loss (NOL) which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010. The 2011 and 2012 federal and state NOLs will be carried forward to offset future taxable income.
[2]	The quarter ended March 31, 2011, includes a reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case.
[3]	The increase in valuation allowance in 2012 is from renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

Earnings Per Share and Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Earnings Per Share and Common Stock [Abstract]
Antidilutive Shares Excluded from EPS Computation	0.2	0.4
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 24.4	$ 37.2
Common Shares	36.8	34.6
Earnings Per Share	$ 0.66	$ 1.07
Dilutive Securities (Shares)	0.1	0.1
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE	$ 24.4	$ 37.2
Common Shares	36.9	34.7
Earnings Per Share	$ 0.66	$ 1.07

Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	$ 2.3	$ 1.9
Interest Cost	6.6	6.9
Expected Return on Plan Assets	(8.8)	(8.7)
Amortization of Prior Service Costs	0.1	0.1
Amortization of Net Loss	4.3	3.0
Net Periodic Benefit Expense	4.5	3.2
Contributions	0.0	0.0
Estimated Future Contributions	1.0
Other Postretirement [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	1.0	1.0
Interest Cost	2.4	2.7
Expected Return on Plan Assets	(2.5)	(2.4)
Amortization of Prior Service Costs	(0.4)	(0.4)
Amortization of Net Loss	1.9	2.1
Net Periodic Benefit Expense	2.4	3.0
Contributions	0.0	$ 10.9
Estimated Future Contributions	13.9
Prescription Drug Reimbursements	$ 0.3

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) MWh in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($) MW MWh Years kV shares
Power Purchase Agreements [Line Items]
Number of Wind PPAs	2
Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
PPA Expiration Date	2026
Generating Unit Capacity (MW) \| shares	455
Share of Plant Output (Percent)	50.00%
Total Debt Outstanding \| $	$ 429.8
Annual Debt Service \| $	$ 44.0
Minnkota Power Sales Agreement [Member]
Power Purchase Agreements [Line Items]
PPA Expiration Date	2025
Anticipated Date of New Transmission Line	2013
Oliver Wind I PPA [Member]
Power Purchase Agreements [Line Items]
PPA Start Date	2006
Share of Plant Output (MW)	50
Oliver Wind II PPA [Member]
Power Purchase Agreements [Line Items]
PPA Start Date	2007
Share of Plant Output (MW)	48
Oliver Wind I and II PPA [Member]
Power Purchase Agreements [Line Items]
Term of PPA (Years) \| Years	25
Manitoba Hydro PPA (expires April 2015) [Member]
Power Purchase Agreements [Line Items]
PPA Expiration Date	April 2015
Share of Plant Output (MW)	50
Manitoba Hydro PPA (expires April 2022) [Member]
Power Purchase Agreements [Line Items]
PPA Start Date	May 2011
PPA Expiration Date	April 2022
Share of Plant Output (MWh) \| MWh	1.0
Date of MPUC Approval	March 2011
Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
PPA Start Date	2020
Term of PPA (Years) \| Years	15
Transmission Line Capacity (kV) \| kV	500
Share of Plant Output (MW)	250
Date of MPUC Approval	January 26, 2012
DC Transmission Line from Square Butte [Member]
Power Purchase Agreements [Line Items]
Transmission Line Purchase Date	December 2009
Transmission Line Capacity (kV) \| kV	250

Commitments, Guarantees and Contingencies - North Dakota Wind Development (Details) $ in Millions	Mar. 31, 2012 USD ($) MW Miles kV	Dec. 31, 2011 USD ($)
North Dakota Wind Development [Line Items]
Capital Cost Spent to Date	$ 33.5	$ 27.8
Bison 1 Wind Project [Member]
North Dakota Wind Development [Line Items]
Number of Phases	2
Generating Unit Capacity (MW) \| MW	82
Transmission Line Capacity (kV) \| kV	230
Total Project Cost	$ 173.8
Transmission Line Length (Miles) \| Miles	22
MPUC, Updated Rates, Order Date	November 3, 2011
Bison 1 Wind Project, Land Restoration and Upgrades [Member]
North Dakota Wind Development [Line Items]
Expected Capital Cost	$ 3.6
Capital Cost Spent to Date	$ 2.6
Bison 1 Wind Project, Phase 1 [Member]
North Dakota Wind Development [Line Items]
Project Completion Date	2010
Bison 1 Wind Project, Phase 2 [Member]
North Dakota Wind Development [Line Items]
Project Completion Date	January 2012
Bison 2 Wind Project [Member]
North Dakota Wind Development [Line Items]
Capital Cost Spent to Date	$ 40.3
MPUC, Project, Approval Date	September 2011
NDPSC, Site Permit, Approval Date	August 2011
Bison 3 Wind Project [Member]
North Dakota Wind Development [Line Items]
Capital Cost Spent to Date	$ 25.8
MPUC, Project, Approval Date	November 2011
NDPSC, Site Permit, Approval Date	October 2011
Bison 2 and 3 Wind Projects, Each [Member]
North Dakota Wind Development [Line Items]
Generating Unit Capacity (MW) \| MW	105
Project Completion Date	2012
Expected Capital Cost	$ 160.0
DC Transmission Line from Square Butte [Member]
North Dakota Wind Development [Line Items]
Transmission Line Capacity (kV) \| kV	250
Transmission Line Length (Miles) \| Miles	465

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) $ in Millions	Mar. 31, 2012 USD ($)
Coal, Rail and Shipping Contracts [Line Items]
Coal Contracts, Expiration Date	2013
Transportation Contracts, Expiration Date	2015
Coal and Transportation [Member]
Coal, Rail and Shipping Contracts [Line Items]
Minimum Annual Payment Obligation, Current Year	$ 37.4
Minimum Annual Payment Obligation, Year Two	$ 23.8

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) $ in Millions	Mar. 31, 2012 USD ($)
Leasing Agreements [Line Items]
Operating Leases, Future Minimum Payments Due, Current	$ 10.9
Operating Leases, Future Minimum Payments, Due in Two Years	11.1
Operating Leases, Future Minimum Payments, Due in Three Years	11.4
Operating Leases, Future Minimum Payments, Due in Four Years	11.2
Operating Leases, Future Minimum Payments, Due in Five Years	9.2
Operating Leases, Future Minimum Payments, Due Thereafter	43.0
BNI Coal Dragline Lease
Leasing Agreements [Line Items]
Annual Lease Payment	$ 2.8
Leasing Agreement Expiration Date	2027
Termination Fee	$ 3.0

Commitments, Guarantees and Contingencies - Transmission (Details) $ in Millions	Mar. 31, 2012 USD ($) Miles kV	Dec. 31, 2011 USD ($)
Transmission [Line Items]
MPUC, Billing Factor, Approval Date	May 2011
MPUC, Updated Billing Factor, Filing Date	June 2011
MPUC, Updated Billing Factor, Expected Approval Date	2012
Number of CapX2020 Projects	3
Minimum Amount Expected to be Invested in Transmission Projects \| $	$ 100.0
Maximum Amount Expected to be Invested in Transmission Projects \| $	125.0
Capital Cost Spent to Date \| $	$ 33.5	$ 27.8
CapX2020 Fargo to St. Cloud Project [Member]
Transmission [Line Items]
MPUC, Route Permit, Approval Date	June 2011
In Service Date	2015
CapX2020 Monticello to St. Cloud Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	28
Transmission Line Capacity (kV) \| kV	345
MPUC, Route Permit, Approval Date	July 2010
Project Completion Date	December 2011
CapX2020 Bemidji to Grand Rapids Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	70
Transmission Line Capacity (kV) \| kV	230
MPUC, Route Permit, Approval Date	November 2010
Construction Start Date	January 2011
CapX2020 Fargo to Monticello Projects [Member]
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	238
Transmission Line Capacity (kV) \| kV	345

Commitments, Guarantees and Contingencies - Air (Details) - Boswell Unit 4 [Member] $ in Millions	Mar. 31, 2012 USD ($)
Maximum [Member]
Expected Capital Cost	$ 400
Minimum [Member]
Expected Capital Cost	$ 300

Commitments, Guarantees and Contingencies - Solid and Hazardous Waste (Details) $ in Millions	Mar. 31, 2012 USD ($)
Manufactured Gas Plant Site [Member]
Solid and Hazardous Waste [Line Items]
Remediation Costs Liability	$ 0.5

Commitments, Guarantees and Contingencies - Other Matters (Details) $ in Millions	Mar. 31, 2012 USD ($) Years	Dec. 31, 2011
BNI Coal Reclamation Liability [Member]
Surety Bonds [Abstract]
Surety Bonds Outstanding	$ 29.8
Total amount of letter of credit secured in addition to surety bonds for reclamation liability	2.6
Total current estimated reclamation liability	32.4
ALLETE Properties Performance and Maintenance Obligations [Member]
Surety Bonds [Abstract]
Surety Bonds Outstanding	10.2
Performance and Maintenance Obligations	7.4
Performance and Maintenance Obligations, Land Purchaser Contractual Obligation	$ 0.5
Community Development Districts [Member]
Capital Improvement Revenue/Special Assessment Bonds [Abstract]
Term (Years) \| Years	31
Town Center Community Development District [Member]
Capital Improvement Revenue/Special Assessment Bonds [Abstract]
Date Issued	March 2005
Amount	$ 26.4
Interest Rate	6.00%
Ownership Percentage of Benefited Property	73.00%	73.00%
Annual Assessments Based on Ownership Percentage	$ 1.5
Palm Coast Park Community Development District [Member]
Capital Improvement Revenue/Special Assessment Bonds [Abstract]
Date Issued	May 2006
Amount	$ 31.8
Interest Rate	5.70%
Ownership Percentage of Benefited Property	93.00%	93.00%
Annual Assessments Based on Ownership Percentage	$ 2.2

Commitments, Guarantees and Contingencies - Legal Proceedings (Details) $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($)
Pending or Threatened Litigation [Member]
Legal Proceedings [Line Items]
Loss Contingency, Damages Sought, Value	$ 20.0

- Definition

The value (monetary amount) of the award the plaintiff seeks in the legal matter.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 11
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14326-108349

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 9
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14557-108349

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details