Document and Entity Information Document (USD $)	9 Months Ended
Document and Entity Information Document (USD $)	Sep. 30, 2013	Jun. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 1,591,836,880
Entity Common Stock, Shares Outstanding	40,736,213
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets [Abstract]
Cash and Cash Equivalents	$ 164.5	$ 80.8
Accounts Receivable (Less Allowance of $1.1 and $1.0)	79.9	89.0
Inventories	64.7	69.8
Prepayments and Other	29.2	33.6
Deferred Income Taxes	30.7	0
Total Current Assets	369.0	273.2
Property, Plant and Equipment - Net	2,456.1	2,347.6
Regulatory Assets	340.3	340.3
Investment in ATC	112.7	107.3
Other Investments	142.9	143.5
Other Non-Current Assets	42.9	41.5
Total Assets	3,463.9	3,253.4
Current Liabilities [Abstract]
Accounts Payable	84.3	90.5
Accrued Taxes	26.1	30.2
Accrued Interest	14.9	15.6
Long-Term Debt Due Within One Year	37.7	84.5
Notes Payable	1.2	0
Other	59.3	62.6
Total Current Liabilities	223.5	283.4
Long-Term Debt	1,064.2	933.6
Deferred Income Taxes	474.9	423.8
Regulatory Liabilities	68.7	60.1
Defined Benefit Pension and Other Postretirement Benefit Plans	216.0	228.2
Other Non-Current Liabilities	129.1	123.3
Total Liabilities	2,176.4	2,052.4
Commitments, Guarantees and Contingencies (Note 14)
Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 40.7 and 39.4 Shares Outstanding	849.8	784.7
Unearned ESOP Shares	(15.1)	(21.3)
Accumulated Other Comprehensive Loss	(21.3)	(22.0)
Retained Earnings	474.1	459.6
Total Equity	1,287.5	1,201.0
Total Liabilities and Equity	$ 3,463.9	$ 3,253.4

Consolidated Balance Sheet Parentheticals (USD $) In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.1	$ 1.0
Common Stock [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	40.7	39.4

Consolidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenue	$ 251.0	$ 248.8	$ 750.4	$ 705.2
Operating Expenses [Abstract]
Fuel and Purchased Power	80.5	79.5	245.7	228.7
Operating and Maintenance	102.7	98.7	311.2	294.8
Depreciation	29.4	25.0	86.3	74.4
Total Operating Expenses	212.6	203.2	643.2	597.9
Operating Income	38.4	45.6	107.2	107.3
Other Income (Expense) [Abstract]
Interest Expense	(12.7)	(12.3)	(37.8)	(33.4)
Equity Earnings in ATC	4.9	4.9	15.1	14.3
Other	3.3	1.5	7.5	3.4
Total Other Expense	(4.5)	(5.9)	(15.2)	(15.7)
Income Before Income Taxes	33.9	39.7	92.0	91.6
Income Tax Expense	8.7	10.3	20.3	23.4
Net Income	$ 25.2	$ 29.4	$ 71.7	$ 68.2
Average Shares of Common Stock [Abstract]
Basic	39.8	37.7	39.4	37.3
Diluted	39.9	37.8	39.5	37.3
Basic Earnings Per Share of Common Stock	$ 0.63	$ 0.78	$ 1.82	$ 1.83
Diluted Earnings Per Share of Common Stock	$ 0.63	$ 0.78	$ 1.81	$ 1.83
Dividends Per Share of Common Stock	$ 0.475	$ 0.46	$ 1.425	$ 1.38

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Comprehensive Income (Loss) [Abstract]
Net Income	$ 25.2	$ 29.4	$ 71.7	$ 68.2
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities, Net of Income Taxes of $(0.3), $0.5, $(0.2) and $0.7	(0.5)	0.5	(0.4)	1.0
Unrealized Gain (Loss) on Derivatives, Net of Income Taxes of $(0.1), $(0.1), $- and $(0.2)	(0.1)	0	0	(0.2)
Defined Benefit Pension and Other Postretirement Benefit Plans, Net of Income Taxes of $0.3, $0.2, $0.8 and $0.9	0.3	0.4	1.1	1.4
Total Other Comprehensive Income (Loss)	(0.3)	0.9	0.7	2.2
Comprehensive Income	$ 24.9	$ 30.3	$ 72.4	$ 70.4

- Definition

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

+ References+ Details

Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain (Loss) on Securities, Tax	$ (0.3)	$ 0.5	$ (0.2)	$ 0.7
Unrealized Gain (Loss) on Derivatives, Tax	(0.1)	(0.1)	0	(0.2)
Defined Benefit Pension and Other Postretirement Benefit Plans, Tax	$ 0.3	$ 0.2	$ 0.8	$ 0.9

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating Activities [Abstract]
Net Income	$ 71.7	$ 68.2
Allowance for Funds Used During Construction - Equity	(3.4)	(3.4)
Income from Equity Investments, Net of Dividends	(3.1)	(2.7)
Gain on Sale of Assets	(0.2)	0
Gain on Sale of Investments	(2.2)	0
Depreciation Expense	86.3	74.4
Amortization of Debt Issuance Costs	0.8	0.7
Deferred Income Tax Expense	20.4	23.4
Share-Based Compensation Expense	1.8	1.7
ESOP Compensation Expense	6.0	5.5
Defined Benefit Pension and Postretirement Benefit Expense	16.8	20.6
Bad Debt Expense	0.9	0.9
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	8.2	5.6
Inventories	5.1	(7.6)
Prepayments and Other	4.4	3.3
Accounts Payable	3.9	(1.3)
Other Current Liabilities	(8.8)	7.4
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans	(10.8)	0
Changes in Regulatory and Other Non-Current Assets	(13.5)	(5.0)
Changes in Regulatory and Other Non-Current Liabilities	4.6	3.8
Cash from Operating Activities	188.9	195.5
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	15.0	1.2
Payments for Purchase of Available-for-sale Securities	(2.8)	(1.5)
Investment in ATC	(2.3)	(3.9)
Changes to Other Investments	(10.5)	(5.5)
Additions to Property, Plant and Equipment	(195.3)	(331.9)
Proceeds from Sale of Assets	0.9	0
Cash for Investing Activities	(195.0)	(341.6)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	63.3	52.1
Proceeds from Issuance of Long-Term Debt	150.0	175.6
Changes in Notes Payable	1.2	(0.8)
Payments for Long-Term Debt	(66.2)	(24.1)
Debt Issuance Costs	(1.3)	(1.3)
Dividends on Common Stock	(57.2)	(52.2)
Cash from Financing Activities	89.8	149.3
Change in Cash and Cash Equivalents	83.7	3.2
Cash and Cash Equivalents at Beginning of Period	80.8	101.1
Cash and Cash Equivalents at End of Period	$ 164.5	$ 104.3

Operations and Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

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	September 30, 2013		December 31, 2012
Millions
Fuel		$18.3		$28.0
Materials and Supplies	46.4		41.8
Total Inventories		$64.7		$69.8



Prepayments and Other Current Assets	September 30, 2013		December 31, 2012
Millions
Deferred Fuel Adjustment Clause		$22.8		$22.5
Other	6.4		11.1
Total Prepayments and Other Current Assets		$29.2		$33.6



Other Current Liabilities	September 30, 2013		December 31, 2012
Millions
Customer Deposits		$27.5		$28.8
Other	31.8		33.8
Total Other Current Liabilities		$59.3		$62.6



Other Non-Current Liabilities	September 30, 2013		December 31, 2012
Millions
Asset Retirement Obligation		$82.6		$77.9
Other	46.5		45.4
Total Other Non-Current Liabilities		$129.1		$123.3

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flows Information.



For the Nine Months Ended September 30,	2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$36.0		$32.3
Cash Paid During the Period for Income Taxes		$0.6		$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(10.0)		$(13.1)
Capitalized Asset Retirement Costs		$1.9		$2.4
AFUDC – Equity		$3.4		$3.4

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.

Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued an accounting standard update on disclosure of amounts reclassified out of accumulated other comprehensive income. This update requires entities to provide information about amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This guidance, which was adopted beginning with the quarter ended March 31, 2013, and required additional disclosures, did not have an impact on our consolidated financial position, results of operations, or cash flows. (See Note 11. Reclassifications Out of Accumulated Other Comprehensive Income (Loss).)

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

Business Segments

9 Months Ended

Sep. 30, 2013

Business Segments [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 6,000 acres of land in Minnesota, and earnings on cash and investments.



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended September 30, 2013
Operating Revenue		$251.0			$226.4			$24.6
Fuel and Purchased Power Expense	80.5			80.5			—
Operating and Maintenance Expense	102.7			78.6			24.1
Depreciation Expense	29.4			27.9			1.5
Operating Income (Loss)	38.4			39.4			(1.0		)
Interest Expense	(12.7		)	(10.4		)	(2.3		)
Equity Earnings in ATC	4.9			4.9			—
Other Income	3.3			1.2			2.1
Income (Loss) Before Income Taxes	33.9			35.1			(1.2		)
Income Tax Expense (Benefit)	8.7			10.5			(1.8		)
Net Income		$25.2			$24.6			$0.6



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended September 30, 2012
Operating Revenue		$248.8			$226.4			$22.4
Fuel and Purchased Power Expense	79.5			79.5			—
Operating and Maintenance Expense	98.7			76.4			22.3
Depreciation Expense	25.0			23.5			1.5
Operating Income (Loss)	45.6			47.0			(1.4		)
Interest Expense	(12.3		)	(10.2		)	(2.1		)
Equity Earnings in ATC	4.9			4.9			—
Other Income	1.5			1.5			—
Income (Loss) Before Income Taxes	39.7			43.2			(3.5		)
Income Tax Expense (Benefit)	10.3			13.9			(3.6		)
Net Income		$29.4			$29.3		$0.1



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Nine Months Ended September 30, 2013
Operating Revenue		$750.4			$683.6			$66.8
Fuel and Purchased Power Expense	245.7			245.7			—
Operating and Maintenance Expense	311.2			243.6			67.6
Depreciation Expense	86.3			81.8			4.5
Operating Income (Loss)	107.2			112.5			(5.3		)
Interest Expense	(37.8		)	(31.5		)	(6.3		)
Equity Earnings in ATC	15.1			15.1			—
Other Income	7.5			3.4			4.1
Income (Loss) Before Income Taxes	92.0			99.5			(7.5		)
Income Tax Expense (Benefit)	20.3			26.5			(6.2		)
Net Income (Loss)		$71.7			$73.0		$(1.3)

As of September 30, 2013
Total Assets		$3,463.9			$3,086.3			$377.6
Property, Plant and Equipment – Net		$2,456.1			$2,384.1			$72.0
Accumulated Depreciation		$1,225.3			$1,165.8			$59.5
Capital Additions		$186.4			$177.6			$8.8



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Nine Months Ended September 30, 2012
Operating Revenue		$705.2			$642.0			$63.2
Fuel and Purchased Power Expense	228.7			228.7			—
Operating and Maintenance Expense	294.8			230.6			64.2
Depreciation Expense	74.4			70.1			4.3
Operating Income (Loss)	107.3			112.6			(5.3		)
Interest Expense	(33.4		)	(29.7		)	(3.7		)
Equity Earnings in ATC	14.3			14.3			—
Other Income (Expense)	3.4			3.5			(0.1		)
Income (Loss) Before Income Taxes	91.6			100.7			(9.1		)
Income Tax Expense (Benefit)	23.4			32.6			(9.2		)
Net Income		$68.2			$68.1		$0.1

As of September 30, 2012
Total Assets		$3,138.1			$2,830.9			$307.2
Property, Plant and Equipment – Net		$2,239.9			$2,180.8			$59.1
Accumulated Depreciation		$1,146.7			$1,091.5			$55.2
Capital Additions		$318.3			$312.6			$5.7

- Definition

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

+ References

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+ Details

Investments

9 Months Ended

Sep. 30, 2013

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 in other postretirement plans to fund employee benefits, the cash equivalents within these plans, and other assets consisting primarily of land in Minnesota.



Other Investments	September 30, 2013		December 31, 2012
Millions
ALLETE Properties		$91.2		$91.1
Available-for-sale Securities (a)	16.1		26.8
Cash Equivalents	31.2		20.7
Other	4.4		4.9
Total Other Investments		$142.9		$143.5


(a)	As of September 30, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.8 million, in one year to less than three years was $4.8 million, in three years to less than five years was $2.0 million, and in five or more years was $1.3 million.



ALLETE Properties	September 30, 2013		December 31, 2012
Millions
Land Inventory Beginning Balance		$86.5		$86.0
Cost of Sales	—		(0.2		)
Other	0.2		0.7
Land Inventory Ending Balance	86.7		86.5
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4		1.4
Other	3.1		3.2
Total Real Estate Assets		$91.2		$91.1

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 nine months ended September 30, 2013 (none for the year ended December 31, 2012).

Long-Term Finance Receivables. As of September 30, 2013, long-term finance receivables were $1.4 million net of allowance ($1.4 million net of allowance as of December 31, 2012). 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 September 30, 2013, we had an allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2012).

Derivatives	9 Months Ended
Derivatives	Sep. 30, 2013
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES We have two variable-to-fixed interest rate swaps (Swaps), designated as cash flow hedges, in order to manage the interest rate risk associated with a $75.0 million Term Loan which represents approximately 7 percent of the Company’s outstanding long-term debt as of September 30, 2013. (See Note 8. Short-Term and Long-Term Debt.) The Swaps have effective dates of August 25, 2011, and August 26, 2014, and mature on August 25, 2014 and 2015, respectively. The Swaps involve the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreements at 0.825 percent and 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swaps are expected to be highly effective. If it is determined the Swaps cease to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessments of hedge effectiveness resulted in no ineffectiveness recorded for the quarter and nine months ended September 30, 2013. As of September 30, 2013, the fair value of the Swaps was a $0.6 million liability ($0.7 million liability as of December 31, 2012) of which $0.2 million ($0.7 million as of December 31, 2012) was included in other non-current liabilities and $0.4 million (zero as of December 31, 2012) was included in other current liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swaps were recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

- Definition

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

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+ Details

Fair Value

9 Months Ended

Sep. 30, 2013

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 2012 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 September 30, 2013, and December 31, 2012. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the tables below.



	Fair Value as of September 30, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$7.2	—		—		$7.2
Available-for-sale – Corporate Debt Securities	—			$8.9	—	8.9
Cash Equivalents	31.2		—		—	31.2
Total Fair Value of Assets		$38.4		$8.9	—		$47.3

Liabilities:
Deferred Compensation	—			$15.8	—		$15.8
Derivatives – Interest Rate Swap	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$16.4	—		$16.4

Total Net Fair Value of Assets (Liabilities)		$38.4	$(7.5)		—		$30.9

NOTE 5. FAIR VALUE (Continued)



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$18.0	—		—		$18.0
Available-for-sale – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7

Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

There was no activity in Level 3 during the nine months ended September 30, 2013 and 2012.

The Company’s policy is to recognize transfers in and transfers out of a given level as of the actual date of the event or of the change in circumstances that caused the transfer. For the nine months ended September 30, 2013 and 2012, there were no transfers in or out of Levels 1, 2 or 3.

Fair Value of Financial Instruments. With the exception of the item listed in the table below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed below was based on quoted market prices for the same or similar instruments (Level 2).



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
September 30, 2013	$1,101.9	$1,153.6
December 31, 2012	$1,018.1	$1,143.7

- Definition

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

+ References+ Details

Regulatory Matters

9 Months Ended

Sep. 30, 2013

Regulatory Matters [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, the FERC or the PSCW.

2010 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being 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 desired 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. In January 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On September 18, 2013, the Court issued its opinion affirming the MPUC’s interim rate decision. The decision has no impact on the Company’s consolidated financial position, results of operations, or cash flows.

NOTE 6. REGULATORY MATTERS (Continued)

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’s formula-based contract with the City of Nashwauk is effective April 1, 2013, through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The cost-based formula methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 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 wholesale customer submitted a cancellation notice with termination effective on December 31, 2013. The 17 MW of average monthly demand currently provided to this wholesale customer is expected to be used, upon termination, to supply power for prospective additional retail and municipal load.

2012 Wisconsin Rate Case. SWL&P’s 2013 retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity. The new rates reflect an average overall increase of 2.4 percent for retail customers (a 13.8 percent increase in water rates, a 1.2 percent increase in electric rates, and a 0.2 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $1.7 million in additional revenue.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. The continued use of the 2009 billing factor was approved by the MPUC in May 2011, which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In June 2011, Minnesota Power filed an updated billing factor which was approved by the MPUC at a hearing on September 19, 2013.

Renewable Cost Recovery Rider. The Bison Wind Energy Center in North Dakota currently consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC and are based on investments and expenditures through March 2012. Minnesota Power filed a cost recovery petition with the MPUC on May 31, 2013, to update customer billing rates for subsequent investments and expenditures since March 2012, which is expected to be approved in the fourth quarter of 2013. On September 25, 2013, the NDPSC approved the site permit for construction of Bison 4, a 205 MW wind project in North Dakota. As a result, construction has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $7.7 million was spent through September 30, 2013. On September 27, 2013, Minnesota Power filed its petition with the MPUC seeking current cost recovery for investments and expenditures related to Bison 4.

Rapids Energy Center. In December 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill (Blandin). Minnesota Power and Blandin entered into a new electric service agreement in September 2012, which was also subject to MPUC approval. On October 9, 2013, the MPUC issued an order denying, without prejudice, the transfer of assets from non-rate base generation to Minnesota Power’s Regulated Operations. In addition, on September 26, 2013, we filed a request to withdraw the electric service agreement, subject to MPUC acceptance. These decisions had no impact on the Company’s consolidated financial position, results of operations, or cash flows.

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

Integrated Resource Plan. At a hearing on September 25, 2013, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class.

NOTE 6. REGULATORY MATTERS (Continued)

Boswell Mercury Emissions Reduction Plan. Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $350 million. At a hearing on September 25, 2013, the MPUC approved the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. In the fourth quarter of 2013, we will file a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, the 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 the PPACA. In May 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.

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	September 30, 2013		December 31, 2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.8		$22.5
Total Current Regulatory Assets	22.8		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	247.0		260.7
Income Taxes	34.4		36.0
Asset Retirement Obligations	14.9		12.1
Cost Recovery Riders (b)	35.5		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.5		3.7
Total Non-Current Regulatory Assets	340.3		340.3

Total Regulatory Assets		$363.1		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.7		$19.5
Plant Removal Obligations	20.4		18.1
Wholesale and Retail Contra AFUDC	17.7		15.5
Conservation Improvement Program	5.8		—
Other	7.1		7.0
Total Non-Current Regulatory Liabilities		$68.7		$60.1


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


(b)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center.

Investment in ATC

9 Months Ended

Sep. 30, 2013

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 September 30, 2013, our equity investment in ATC was $112.7 million ($107.3 million at December 31, 2012). In the first nine months of 2013, we invested $2.3 million in ATC, and on October 30, 2013, we invested an additional $0.8 million. We do not expect to make any additional investments in 2013.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2012		$107.3
Cash Investments	2.3
Equity in ATC Earnings	15.1
Distributed ATC Earnings	(12.0		)
Equity Investment Balance as of September 30, 2013		$112.7

ATC’s summarized financial data for the quarters and nine months ended September 30, 2013 and 2012, is as follows:



	Quarter Ended			Nine Months Ended
ATC Summarized Financial Data	September 30,			September 30,
Income Statement Data	2013		2012	2013		2012
Millions
Revenue		$160.5	$150.3		$464.3		$450.1
Operating Expense	77.6		68.8	217.2		210.1
Other Expense	20.2		21.0	62.6		62.1
Net Income		$62.7	$60.5		$184.5		$177.9
ALLETE’s Equity in Net Income		$4.9	$4.9		$15.1		$14.3

- Definition

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

+ References+ Details

Short-Term and Long-Term Debt

9 Months Ended

Sep. 30, 2013

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 September 30, 2013, total short-term debt outstanding was $38.9 million ($84.5 million as of December 31, 2012) and consisted of long-term debt due within one year and notes payable. Short-term debt as of December 31, 2012 included $60.0 million of long-term debt that matured in April 2013.

Long-Term Debt. As of September 30, 2013, total long-term debt outstanding was $1,064.2 million ($933.6 million as of December 31, 2012).

On April 2, 2013, we issued $150.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in three series as follows:



Maturity Date	Principal Amount	Interest Rate
April 15, 2018	$50 Million	1.83%
October 15, 2028	$40 Million	3.30%
October 15, 2043	$60 Million	4.21%

We have the option to prepay all or a portion of the 1.83 percent Bonds at our discretion at any time, subject to a make-whole provision. We have the option to prepay all or a portion of the 3.30 percent Bonds at our discretion at any time prior to April 15, 2028, subject to a make-whole provision, and at any time on or after April 15, 2028, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the 4.21 percent Bonds at our discretion at any time prior to April 15, 2043, subject to a make-whole provision, and at any time on or after April 15, 2043, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to additional terms and conditions of our utility mortgage. Proceeds from the sale of the Bonds will be used to fund utility capital investments, repay debt, and/or for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors in a private placement.

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

On August 26, 2013, we amended our $75.0 million Term Loan with JPMorgan Chase Bank, N.A. (Term Loan). The Term Loan was amended to extend the maturity date an additional year to August 25, 2015, and to lower the interest rate to the one-month LIBOR plus 0.875 percent. There was no change to the original interest rate swap agreement which remains in effect through August 25, 2014, and effectively fixes the interest rate for the amended Term Loan at 1.70 percent through August 25, 2014. We also entered into a new interest swap agreement covering the final year of the amended Term Loan which effectively fixes the interest rate at 1.625 percent from August 26, 2014, through August 25, 2015. (See also Note 4. Derivatives.)

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 September 30, 2013, our ratio was approximately 0.46 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from a lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of September 30, 2013, 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

Income Tax Expense

9 Months Ended

Sep. 30, 2013

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Millions
Current Tax Expense (Benefit)
Federal (a)	—			—			—			—
State (a)	$(0.1)			—			$(0.1)			—
Total Current Tax Expense (Benefit)	(0.1)			—			(0.1)			—
Deferred Tax Expense (Benefit)
Federal		$7.3			$10.1			$15.5			$23.3
State (b)	1.7			0.4			5.5			0.7
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.6		)	(0.6		)
Total Deferred Tax Expense	8.8			10.3			20.4			23.4
Total Income Tax Expense		$8.7			$10.3			$20.3			$23.4


(a)	We incurred net operating losses (NOLs) due to the bonus depreciation provisions of the American Taxpayer Relief Act of 2012 and the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010 for the quarter and nine months ended September 30, 2013 and 2012. The 2013 and 2012 federal and state NOLs will be carried forward to offset future taxable income.


(b)	The quarter and nine months ended September 30, 2012 reflected increased state tax benefit from state renewable tax credits compared to the quarter and nine months ended September 30, 2013.

NOTE 10. INCOME TAX EXPENSE (Continued)

For the nine months ended September 30, 2013, the effective tax rate was 22.1 percent (25.5 percent for the nine months ended September 30, 2012). The decrease from the effective tax rate for the nine months ended September 30, 2012, was primarily due to increased federal production 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, federal production tax credits, state income tax credits and depletion.

Uncertain Tax Positions. As of September 30, 2013, we had gross unrecognized tax benefits of $3.2 million ($2.7 million as of December 31, 2012). Of the total gross unrecognized tax benefits, $0.8 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 under review at the IRS appeals office. We expect the IRS appeals process to be completed during the next twelve months, resulting in the reversal of a majority of the unrecognized tax benefits as of September 30, 2013. The unrecognized tax benefits are primarily due to tax positions which are timing in nature and therefore would have an immaterial impact on our effective tax rate if recognized.

- 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+ Details

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2013

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

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

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive loss, net of tax, for the quarter and nine months ended September 30, 2013, were as follows:



	Unrealized Gains and Losses on Available-for-sale Securities	Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
For the Quarter Ended September 30, 2013
Beginning Accumulated Other Comprehensive Loss	—	$(20.7)	$(0.3)	$(21.0)
Other Comprehensive Income (Loss) Before Reclassifications	$0.3	—	(0.1)	0.2
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(0.8)	0.3	—	(0.5)
Net Other Comprehensive Income (Loss)	(0.5)	0.3	(0.1)	(0.3)
Ending Accumulated Other Comprehensive Loss	$(0.5)	$(20.4)	$(0.4)	$(21.3)

For the Nine Months Ended September 30, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)	$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income Before Reclassifications	0.9	—	—	0.9
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(1.3)	1.1	—	(0.2)
Net Other Comprehensive Income (Loss)	(0.4)	1.1	—	0.7
Ending Accumulated Other Comprehensive Loss	$(0.5)	$(20.4)	$(0.4)	$(21.3)

NOTE 11. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

Reclassifications from accumulated other comprehensive loss for the quarter and nine months ended September 30, 2013, were as follows:



	Quarter Ended	Nine Months Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	September 30,	September 30,
	2013	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$1.4	$2.2
Income Taxes (b)	(0.6)	(0.9)
Total, Net of Income Taxes	$0.8	$1.3

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.1	$0.2
Actuarial Gains and Losses (c)	(0.7)	(2.1)
Total	(0.6)	(1.9)
Income Taxes (b)	0.3	0.8
Total, Net of Income Taxes	$(0.3)	$(1.1)
Total Reclassifications	$0.5	$0.2


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


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


(c)	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense (See Note 13. Pension and Other Postretirement Benefit Plans).

- Definition

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

+ References+ Details

Earnings Per Share and Common Stock

9 Months Ended

Sep. 30, 2013

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, non-vested restricted stock units, and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the quarters and nine months ended September 30, 2013 and 2012, zero and 0.2 million options to purchase shares of common stock, respectively, were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.



			2013					2012
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 September 30,
Net Income		$25.2			$25.2		$29.4			$29.4
Average Common Shares	39.8		0.1	39.9		37.7		0.1	37.8
Earnings Per Share		$0.63			$0.63		$0.78			$0.78
For the Nine Months Ended September 30,
Net Income		$71.7			$71.7		$68.2			$68.2
Average Common Shares	39.4		0.1	39.5		37.3		—	37.3
Earnings Per Share		$1.82			$1.81		$1.83			$1.83

- Definition

The entire disclosure for earnings per share.

+ References+ Details

Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2013

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	2013			2012			2013			2012
Millions
For the Quarter Ended September 30,
Service Cost		$2.4			$2.3			$0.9			$1.0
Interest Cost	6.5			6.6			1.7			2.4
Expected Return on Plan Assets	(8.8		)	(8.9		)	(2.4		)	(2.5		)
Amortization of Prior Service Costs	0.1			—			(0.6		)	(0.4		)
Amortization of Net Loss	5.4			4.4			0.4			1.9
Net Periodic Benefit Expense		$5.6			$4.4		—				$2.4

For the Nine Months Ended September 30,
Service Cost		$7.4			$6.9			$2.9			$3.1
Interest Cost	19.5			19.8			5.1			7.1
Expected Return on Plan Assets	(26.4		)	(26.6		)	(7.3		)	(7.5		)
Amortization of Prior Service Costs	0.2			0.2			(1.9		)	(1.3		)
Amortization of Net Loss	16.1			13.1			1.2			5.7
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$16.8			$13.4		—				$7.2

Employer Contributions. For the nine months ended September 30, 2013, no contributions were made to our defined benefit pension plan (none for the nine months ended September 30, 2012). For the nine months ended September 30, 2013, we contributed $10.8 million to our other postretirement benefit plan (none for the nine months ended September 30, 2012). We do not expect to contribute to our defined benefit pension plan in 2013, and we do not expect to make any additional contributions to our other postretirement benefit plan in 2013.

Commitments, Guarantees and Contingencies

9 Months Ended

Sep. 30, 2013

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 September 30, 2013, Square Butte had total debt outstanding of $404.4 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the years 2013 through 2017, 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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

Minnesota Power’s cost of power purchased from Square Butte during the nine months ended September 30, 2013, was $51.3 million ($48.7 million for the nine months ended September 30, 2012). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $7.9 million during the nine months ended September 30, 2013 ($8.3 million for the nine months ended September 30, 2012). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will sell a portion of its output from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.

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

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016, through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

Oliver Wind I and II PPAs. In 2006 and 2007, Minnesota Power entered into two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW)—wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges and we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in 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 long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and is subject to construction of additional transmission capacity between Manitoba and Minnesota’s Iron Range, along with construction of new hydroelectric generating capacity in Manitoba. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for changes in a governmental inflationary index, a natural gas index, and market prices.

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

Our 292 MW Bison Wind Energy Center, located in North Dakota, was completed in various phases through 2012. On September 25, 2013, the NDPSC approved the site permit for Bison 4, a 205 MW wind project in North Dakota. As a result, construction has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $7.7 million was spent through September 30, 2013. On September 27, 2013, Minnesota Power filed its petition with the MPUC seeking current cost recovery for investments and expenditures related to Bison 4.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements is $12.1 million for the remainder of 2013, $6.9 million for 2014 and $2.2 million for 2015. Our minimum annual payment obligation will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term, which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is $11.5 million in 2013, $11.7 million in 2014, $11.4 million in 2015, $9.3 million in 2016, $8.5 million in 2017 and $35.0 million thereafter.

Transmission. We continue to make investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. These include the Great Northern Transmission Line, the CapX2020 initiative, investments in our own transmission assets, investments in other regional transmission assets (individually or in combination with others), and our investment in ATC.

CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

Minnesota Power is 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. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. 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 was completed in August 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015. A total of $70.9 million was spent through September 30, 2013, of which $60.0 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($48.2 million as of December 31, 2012 of which $37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 240-mile 500 kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

The GNTL is subject to various federal and state regulatory approvals. Before a large energy facility can be sited or constructed in Minnesota, the MPUC requires a Certificate of Need, which was filed on October 21, 2013. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, Minnesota Power anticipates construction to begin in 2016, and to be completed in 2020. Minnesota Power will own 51 percent of the GNTL, while a subsidiary of Manitoba Hydro will own 49 percent. At this time, we expect our portion of capital expenditures for the project to range between $200 million and $300 million depending on the final route of the line.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both Congress and the EPA. Minnesota Power’s fossil fuel facilities will likely be subject to regulation under these proposals. Our intention is to reduce our exposure to these requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to expected future restrictive environmental requirements imposed through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible ranges of future environmental regulations to project power supply trends and impacts on customers.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.

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

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that the Boswell Unit 4’s Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures, that may be required upon resolution. Any costs of installing additional pollution control equipment would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, in August 2012, a three-judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. On March 29, 2013, the EPA petitioned the Supreme Court to review the District of Columbia Circuit Court of Appeals ruling. The Supreme Court decided to grant review on June 24, 2013, and is likely to issue its decision by June 2014. If reinstated after Supreme Court review, the CSAPR would require states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR would not directly require the installation of controls. Instead, the rule would require facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would be allocated to facilities from each state’s annual budget and could be bought and sold.

The CAIR regulations similarly require certain states to improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CAIR also created an allowance allocation and trading program rather than specifying pollution controls. Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA completed a review of air quality modeling issues in conjunction with the development of a final replacement rule. While the CAIR remains in effect, Minnesota participation in the CAIR will continue to be stayed. It remains uncertain if emission restrictions similar to those contained in the CSAPR will become effective for Minnesota utilities as a result of the August 2012 District of Columbia Circuit Court of Appeals decision.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

Regional Haze. The federal Regional Haze Rule requires states to submit SIPs to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the first phase of the Regional Haze Rule, certain large stationary sources, 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, subject to BART requirements.

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

In December 2011, the EPA published in the Federal Register a proposal to approve a trading program in the CSAPR as an alternative to determining BART. However, as a result of the August 2012 District of Columbia Circuit Court of Appeals decision to vacate the CSAPR (See Cross-State Air Pollution Rule), Minnesota Power is now evaluating whether significant additional expenditures at Taconite Harbor Unit 3 will be required to comply with BART requirements under the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation date to bring Taconite Harbor Unit 3 into compliance with the Regional Haze Rule requirements. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC at a hearing held on September 25, 2013, we plan to retire Taconite Harbor Unit 3 in 2015.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $350 million through 2016. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC at a hearing on September 25, 2013, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015, to position the Company for MATS compliance.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2011, a final rule was published in the Federal Register for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT). The rule was stayed by the EPA in May 2011, to allow the EPA time to consider additional comments received. The EPA re-proposed the rule in December 2011. In January 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power is in the process of assessing the impact of this rule on our affected units, Hibbard Renewable Energy Center and Rapids Energy Center. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Minnesota Mercury Emissions Reduction Act. Under the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls to address both the Minnesota mercury emissions reduction requirements and the MATS rule, which also regulates mercury emissions. Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016, was approved by the MPCA. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule discussed (see Mercury and Air Toxics Standards (MATS) Rule).

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA was scheduled to decide upon the 2008 eight-hour ozone standard in July 2011, but has since announced that it is deferring revision of this standard until 2014 or later. Consequently, the costs for complying with the final ozone NAAQS cannot be estimated at this time.

Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM_2.5) standard; the annual PM_2.5 standard and the 24‑hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM_2.5 standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM_2.5 standards in June 2012.

In December 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5 standard, while retaining the current 24-hour PM_2.5standard. To implement the new more stringent annual PM_2.5standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects and permits must comply with the new more stringent standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling.

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. States are expected to propose attainment designations by December 2013, based on already available monitoring data. The EPA believes that most U.S. counties currently already meet the new standard and plans to finalize designations of attainment by December 2014. For those counties that the EPA does not designate as having already met the requirements of the new standard, specific dates for required attainment will depend on technology availability, state permitting goals, potential legal challenges and other factors. Minnesota is anticipating that it will retain attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO₂ and NO₂. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO₂ NAAQS also may require the EPA to evaluate modeling data to determine attainment. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However, the State of Minnesota has delayed completing the documents pending receipt of EPA guidance to states for preparing the SIP submittal. Guidance was expected earlier in 2013 and has been delayed.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO₂ per year. However, in April 2012, the MPCA notified Minnesota Power that such modeling had been suspended as a result of the EPA’s announcement that the June 2013 SIP submittals would no longer require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The MPCA is awaiting updated EPA guidance and will communicate with affected sources once the MPCA has more information on how the state will meet the EPA’s SIP requirements. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

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


•	Expanding our renewable energy supply;


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


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


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

President Obama’s Climate Action Plan. On June 25, 2013, President Obama announced a Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions, as further described below.

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

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

In March 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS would have applied only to new or re-powered units. Based on the volume of comments received, the EPA announced its intent to re-propose the rule.

On September 20, 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for utility CO₂ emissions. The EPA also reaffirmed its plans to propose NSPS or regulatory guidelines for existing fossil fuel-fired electric generating units by June 1, 2014, and to finalize such rules by June 1, 2015. The EPA is soliciting feedback as to the approaches the EPA should consider for regulation of CO₂ under the NSPS provisions of the Clean Air Act. Under the CAP, an approach was described where the EPA will issue regulatory guidelines and objectives to the states, which in turn will submit SIPs for EPA approval that demonstrate how the state will meet or surpass achievement of the EPA targeted objectives. The CAP directs the EPA to require states to submit such SIPs by June 30, 2016.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. In October 15, 2013, the U.S. Supreme Court announced that it would grant review of the Circuit Court’s decision, with such review limited to the question of whether EPA’s regulation of GHGs under the PSD provisions of the Clean Air Act and the Tailoring Rule was permissible. The Supreme Court’s decision is not expected to affect EPA’s authority to regulate CO₂ from fossil fuel-fired electric generating units under the NSPS provisions of the Clean Air Act, but may affect the timing of such regulations.

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

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011, and the EPA is now expected to issue a final rule in November 2013. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Steam Electric Power Generating Effluent Guidelines. On April 19, 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. Instead of proposing a single rule, the EPA proposed eight “options,” of which four are “preferred”. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register on June 7, 2013, and public comments were submitted on September 20, 2013. It is expected that the EPA will issue a final rule in 2014. Compliance with the final rule would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA.

NOTE 14. 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. It is expected that the final rule will be published in 2014. We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Other Matters

BNI Coal. As of September 30, 2013, BNI Coal had surety bonds outstanding of $29.7 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit with CoBANK ACB for an additional $2.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $32.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of September 30, 2013, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in November 2006 for Town Center and November 2007 for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At September 30, 2013, we owned 73 percent of the assessable land in the Town Center District (73 percent at December 31, 2012) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2012). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20.0 million in damages related to the fire. In response to a Motion for Summary Judgment by Minnesota Power, the Court dismissed all of plaintiffs’ claims in an Order dated August 21, 2013. The Order may be appealed to the Minnesota Court of Appeals through November 25, 2013.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of September 30, 2013, because a potential loss is not currently probable or reasonably estimable.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Other. We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. While the resolution of such matters could have a material effect on our results of operations 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)	9 Months Ended
	Sep. 30, 2013
Operations and Significant Accounting Policies [Abstract]
Inventories [Policy Text Block]	Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.
Subsequent Events [Policy Text Block]	The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.
New Accounting Standards [Policy Text Block]	Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued an accounting standard update on disclosure of amounts reclassified out of accumulated other comprehensive income. This update requires entities to provide information about amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This guidance, which was adopted beginning with the quarter ended March 31, 2013, and required additional disclosures, did not have an impact on our consolidated financial position, results of operations, or cash flows. (See Note 11. Reclassifications Out of Accumulated Other Comprehensive Income (Loss).) Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, the FASB issued an accounting standard update on the financial statement presentation of unrecognized tax benefits when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from the disallowance of a tax position or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This guidance will be effective beginning with the quarter ending March 31, 2014 (early adoption is permitted), and is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.
Land Inventory [Policy Text Block]	Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value.
Long-Term Finance Receivables [Policy Text Block]	Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts.
Derivatives [Policy Text Block]	Changes in the fair value of the Swaps were recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.
Fair Value Transfers [Policy Text Block]	The Company’s policy is to recognize transfers in and transfers out of a given level as of the actual date of the event or of the change in circumstances that caused the transfer.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities represent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.
Equity Method Investments [Policy Text Block]	We account for our investment in ATC under the equity method of accounting.
Environmental Costs [Policy Text Block]	We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.

Operations and Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2013

Operations and Significant Accounting Policies [Abstract]

Inventories [Table Text Block]



Inventories	September 30, 2013		December 31, 2012
Millions
Fuel		$18.3		$28.0
Materials and Supplies	46.4		41.8
Total Inventories		$64.7		$69.8

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	September 30, 2013		December 31, 2012
Millions
Deferred Fuel Adjustment Clause		$22.8		$22.5
Other	6.4		11.1
Total Prepayments and Other Current Assets		$29.2		$33.6

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



Other Current Liabilities	September 30, 2013		December 31, 2012
Millions
Customer Deposits		$27.5		$28.8
Other	31.8		33.8
Total Other Current Liabilities		$59.3		$62.6



Other Non-Current Liabilities	September 30, 2013		December 31, 2012
Millions
Asset Retirement Obligation		$82.6		$77.9
Other	46.5		45.4
Total Other Non-Current Liabilities		$129.1		$123.3

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



For the Nine Months Ended September 30,	2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$36.0		$32.3
Cash Paid During the Period for Income Taxes		$0.6		$0.2
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(10.0)		$(13.1)
Capitalized Asset Retirement Costs		$1.9		$2.4
AFUDC – Equity		$3.4		$3.4

Business Segments (Tables)

9 Months Ended

Sep. 30, 2013

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended September 30, 2013
Operating Revenue		$251.0			$226.4			$24.6
Fuel and Purchased Power Expense	80.5			80.5			—
Operating and Maintenance Expense	102.7			78.6			24.1
Depreciation Expense	29.4			27.9			1.5
Operating Income (Loss)	38.4			39.4			(1.0		)
Interest Expense	(12.7		)	(10.4		)	(2.3		)
Equity Earnings in ATC	4.9			4.9			—
Other Income	3.3			1.2			2.1
Income (Loss) Before Income Taxes	33.9			35.1			(1.2		)
Income Tax Expense (Benefit)	8.7			10.5			(1.8		)
Net Income		$25.2			$24.6			$0.6



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended September 30, 2012
Operating Revenue		$248.8			$226.4			$22.4
Fuel and Purchased Power Expense	79.5			79.5			—
Operating and Maintenance Expense	98.7			76.4			22.3
Depreciation Expense	25.0			23.5			1.5
Operating Income (Loss)	45.6			47.0			(1.4		)
Interest Expense	(12.3		)	(10.2		)	(2.1		)
Equity Earnings in ATC	4.9			4.9			—
Other Income	1.5			1.5			—
Income (Loss) Before Income Taxes	39.7			43.2			(3.5		)
Income Tax Expense (Benefit)	10.3			13.9			(3.6		)
Net Income		$29.4			$29.3		$0.1



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Nine Months Ended September 30, 2013
Operating Revenue		$750.4			$683.6			$66.8
Fuel and Purchased Power Expense	245.7			245.7			—
Operating and Maintenance Expense	311.2			243.6			67.6
Depreciation Expense	86.3			81.8			4.5
Operating Income (Loss)	107.2			112.5			(5.3		)
Interest Expense	(37.8		)	(31.5		)	(6.3		)
Equity Earnings in ATC	15.1			15.1			—
Other Income	7.5			3.4			4.1
Income (Loss) Before Income Taxes	92.0			99.5			(7.5		)
Income Tax Expense (Benefit)	20.3			26.5			(6.2		)
Net Income (Loss)		$71.7			$73.0		$(1.3)

As of September 30, 2013
Total Assets		$3,463.9			$3,086.3			$377.6
Property, Plant and Equipment – Net		$2,456.1			$2,384.1			$72.0
Accumulated Depreciation		$1,225.3			$1,165.8			$59.5
Capital Additions		$186.4			$177.6			$8.8



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Nine Months Ended September 30, 2012
Operating Revenue		$705.2			$642.0			$63.2
Fuel and Purchased Power Expense	228.7			228.7			—
Operating and Maintenance Expense	294.8			230.6			64.2
Depreciation Expense	74.4			70.1			4.3
Operating Income (Loss)	107.3			112.6			(5.3		)
Interest Expense	(33.4		)	(29.7		)	(3.7		)
Equity Earnings in ATC	14.3			14.3			—
Other Income (Expense)	3.4			3.5			(0.1		)
Income (Loss) Before Income Taxes	91.6			100.7			(9.1		)
Income Tax Expense (Benefit)	23.4			32.6			(9.2		)
Net Income		$68.2			$68.1		$0.1

As of September 30, 2012
Total Assets		$3,138.1			$2,830.9			$307.2
Property, Plant and Equipment – Net		$2,239.9			$2,180.8			$59.1
Accumulated Depreciation		$1,146.7			$1,091.5			$55.2
Capital Additions		$318.3			$312.6			$5.7

- 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

Fair Value (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of September 30, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$7.2	—		—		$7.2
Available-for-sale – Corporate Debt Securities	—			$8.9	—	8.9
Cash Equivalents	31.2		—		—	31.2
Total Fair Value of Assets		$38.4		$8.9	—		$47.3

Liabilities:
Deferred Compensation	—			$15.8	—		$15.8
Derivatives – Interest Rate Swap	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$16.4	—		$16.4

Total Net Fair Value of Assets (Liabilities)		$38.4	$(7.5)		—		$30.9

NOTE 5. FAIR VALUE (Continued)



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$18.0	—		—		$18.0
Available-for-sale – Corporate Debt Securities	—			$8.8	—	8.8
Cash Equivalents	20.7		—		—	20.7
Total Fair Value of Assets		$38.7		$8.8	—		$47.5

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7

Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
September 30, 2013	$1,101.9	$1,153.6
December 31, 2012	$1,018.1	$1,143.7

- Definition

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

+ References+ Details

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2013

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	September 30, 2013		December 31, 2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$22.8		$22.5
Total Current Regulatory Assets	22.8		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	247.0		260.7
Income Taxes	34.4		36.0
Asset Retirement Obligations	14.9		12.1
Cost Recovery Riders (b)	35.5		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.5		3.7
Total Non-Current Regulatory Assets	340.3		340.3

Total Regulatory Assets		$363.1		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.7		$19.5
Plant Removal Obligations	20.4		18.1
Wholesale and Retail Contra AFUDC	17.7		15.5
Conservation Improvement Program	5.8		—
Other	7.1		7.0
Total Non-Current Regulatory Liabilities		$68.7		$60.1


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


(b)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center.

Investment in ATC (Tables)

9 Months Ended

Sep. 30, 2013

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, 2012		$107.3
Cash Investments	2.3
Equity in ATC Earnings	15.1
Distributed ATC Earnings	(12.0		)
Equity Investment Balance as of September 30, 2013		$112.7

ATC Summarized Financial Data [Table Text Block]

ATC’s summarized financial data for the quarters and nine months ended September 30, 2013 and 2012, is as follows:



	Quarter Ended			Nine Months Ended
ATC Summarized Financial Data	September 30,			September 30,
Income Statement Data	2013		2012	2013		2012
Millions
Revenue		$160.5	$150.3		$464.3		$450.1
Operating Expense	77.6		68.8	217.2		210.1
Other Expense	20.2		21.0	62.6		62.1
Net Income		$62.7	$60.5		$184.5		$177.9
ALLETE’s Equity in Net Income		$4.9	$4.9		$15.1		$14.3

Short-Term and Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2013

Short-Term and Long-Term Debt [Abstract]

First Mortgage Bonds Issuance [Table Text Block]

On April 2, 2013, we issued $150.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in three series as follows:



Maturity Date	Principal Amount	Interest Rate
April 15, 2018	$50 Million	1.83%
October 15, 2028	$40 Million	3.30%
October 15, 2043	$60 Million	4.21%

- Definition

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

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

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

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-Publisher FASB

-Name Accounting Standards Codification

-Topic 835

-SubTopic 30

-Section 55

-Paragraph 8

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

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-Topic 835

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-Topic 835

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-Name Accounting Standards Codification

-Topic 505

-SubTopic 10

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 02

-Paragraph 22

-Article 5

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 210

-SubTopic 10

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-Paragraph 1

-Subparagraph (SX 210.5-02.22)

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+ Details

Income Tax Expense (Tables)

9 Months Ended

Sep. 30, 2013

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Millions
Current Tax Expense (Benefit)
Federal (a)	—			—			—			—
State (a)	$(0.1)			—			$(0.1)			—
Total Current Tax Expense (Benefit)	(0.1)			—			(0.1)			—
Deferred Tax Expense (Benefit)
Federal		$7.3			$10.1			$15.5			$23.3
State (b)	1.7			0.4			5.5			0.7
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.6		)	(0.6		)
Total Deferred Tax Expense	8.8			10.3			20.4			23.4
Total Income Tax Expense		$8.7			$10.3			$20.3			$23.4


(a)	We incurred net operating losses (NOLs) due to the bonus depreciation provisions of the American Taxpayer Relief Act of 2012 and the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010 for the quarter and nine months ended September 30, 2013 and 2012. The 2013 and 2012 federal and state NOLs will be carried forward to offset future taxable income.


(b)	The quarter and nine months ended September 30, 2012 reflected increased state tax benefit from state renewable tax credits compared to the quarter and nine months ended September 30, 2013.

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

9 Months Ended

Sep. 30, 2013

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

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

Changes in accumulated other comprehensive loss, net of tax, for the quarter and nine months ended September 30, 2013, were as follows:



	Unrealized Gains and Losses on Available-for-sale Securities	Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
For the Quarter Ended September 30, 2013
Beginning Accumulated Other Comprehensive Loss	—	$(20.7)	$(0.3)	$(21.0)
Other Comprehensive Income (Loss) Before Reclassifications	$0.3	—	(0.1)	0.2
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(0.8)	0.3	—	(0.5)
Net Other Comprehensive Income (Loss)	(0.5)	0.3	(0.1)	(0.3)
Ending Accumulated Other Comprehensive Loss	$(0.5)	$(20.4)	$(0.4)	$(21.3)

For the Nine Months Ended September 30, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)	$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income Before Reclassifications	0.9	—	—	0.9
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(1.3)	1.1	—	(0.2)
Net Other Comprehensive Income (Loss)	(0.4)	1.1	—	0.7
Ending Accumulated Other Comprehensive Loss	$(0.5)	$(20.4)	$(0.4)	$(21.3)

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

Reclassifications from accumulated other comprehensive loss for the quarter and nine months ended September 30, 2013, were as follows:



	Quarter Ended	Nine Months Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	September 30,	September 30,
	2013	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$1.4	$2.2
Income Taxes (b)	(0.6)	(0.9)
Total, Net of Income Taxes	$0.8	$1.3

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.1	$0.2
Actuarial Gains and Losses (c)	(0.7)	(2.1)
Total	(0.6)	(1.9)
Income Taxes (b)	0.3	0.8
Total, Net of Income Taxes	$(0.3)	$(1.1)
Total Reclassifications	$0.5	$0.2


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


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


(c)	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense (See Note 13. Pension and Other Postretirement Benefit Plans).

Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2013

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	2013			2012			2013			2012
Millions
For the Quarter Ended September 30,
Service Cost		$2.4			$2.3			$0.9			$1.0
Interest Cost	6.5			6.6			1.7			2.4
Expected Return on Plan Assets	(8.8		)	(8.9		)	(2.4		)	(2.5		)
Amortization of Prior Service Costs	0.1			—			(0.6		)	(0.4		)
Amortization of Net Loss	5.4			4.4			0.4			1.9
Net Periodic Benefit Expense		$5.6			$4.4		—				$2.4

For the Nine Months Ended September 30,
Service Cost		$7.4			$6.9			$2.9			$3.1
Interest Cost	19.5			19.8			5.1			7.1
Expected Return on Plan Assets	(26.4		)	(26.6		)	(7.3		)	(7.5		)
Amortization of Prior Service Costs	0.2			0.2			(1.9		)	(1.3		)
Amortization of Net Loss	16.1			13.1			1.2			5.7
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$16.8			$13.4		—				$7.2

Operations and Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Inventories [Abstract]
Fuel	$ 18.3		$ 18.3		$ 28.0
Materials and Supplies	46.4		46.4		41.8
Total Inventories	64.7		64.7		69.8
Prepayments and Other Current Assets [Abstract]
Deferred Fuel Adjustment Clause	22.8		22.8		22.5
Other	6.4		6.4		11.1
Total Prepayments and Other Current Assets	29.2		29.2		33.6
Other Current Liabilites [Abstract]
Customer Deposits	27.5		27.5		28.8
Other	31.8		31.8		33.8
Total Other Current Liabilities	59.3		59.3		62.6
Other Non-Current Liabilities [Abstract]
Asset Retirement Obligation	82.6		82.6		77.9
Other	46.5		46.5		45.4
Total Other Non-Current Liabilities	129.1		129.1		123.3
Supplemental Statement of Cash Flows Information [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized			36.0	32.3
Cash Paid During the Period for Income Taxes			0.6	0.2
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment			(10.0)	(13.1)
Capitalized Asset Retirement Costs			1.9	2.4
AFUDC - Equity	$ 1.2	$ 1.5	$ 3.4	$ 3.4

Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Business Segments [Line Items]
Operating Revenue	$ 251.0	$ 248.8	$ 750.4	$ 705.2
Fuel and Purchased Power Expense	80.5	79.5	245.7	228.7
Operating and Maintenance Expense	102.7	98.7	311.2	294.8
Depreciation Expense	29.4	25.0	86.3	74.4
Operating Income (Loss)	38.4	45.6	107.2	107.3
Interest Expense	(12.7)	(12.3)	(37.8)	(33.4)
Equity Earnings in ATC	4.9	4.9	15.1	14.3
Other Income (Expense)	3.3	1.5	7.5	3.4
Income (Loss) Before Income Taxes	33.9	39.7	92.0	91.6
Income Tax Expense (Benefit)	8.7	10.3	20.3	23.4
Net Income (Loss)	25.2	29.4	71.7	68.2
Total Assets	3,463.9	3,138.1	3,463.9	3,138.1	3,253.4
Property, Plant and Equipment - Net	2,456.1	2,239.9	2,456.1	2,239.9	2,347.6
Accumulated Depreciation	1,225.3	1,146.7	1,225.3	1,146.7
Capital Additions			186.4	318.3
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue	226.4	226.4	683.6	642.0
Fuel and Purchased Power Expense	80.5	79.5	245.7	228.7
Operating and Maintenance Expense	78.6	76.4	243.6	230.6
Depreciation Expense	27.9	23.5	81.8	70.1
Operating Income (Loss)	39.4	47.0	112.5	112.6
Interest Expense	(10.4)	(10.2)	(31.5)	(29.7)
Equity Earnings in ATC	4.9	4.9	15.1	14.3
Other Income (Expense)	1.2	1.5	3.4	3.5
Income (Loss) Before Income Taxes	35.1	43.2	99.5	100.7
Income Tax Expense (Benefit)	10.5	13.9	26.5	32.6
Net Income (Loss)	24.6	29.3	73.0	68.1
Total Assets	3,086.3	2,830.9	3,086.3	2,830.9
Property, Plant and Equipment - Net	2,384.1	2,180.8	2,384.1	2,180.8
Accumulated Depreciation	1,165.8	1,091.5	1,165.8	1,091.5
Capital Additions			177.6	312.6
Investments and Other [Member]
Business Segments [Line Items]
Land in Minnesota (in acres)	6,000		6,000
Operating Revenue	24.6	22.4	66.8	63.2
Fuel and Purchased Power Expense	0	0	0	0
Operating and Maintenance Expense	24.1	22.3	67.6	64.2
Depreciation Expense	1.5	1.5	4.5	4.3
Operating Income (Loss)	(1.0)	(1.4)	(5.3)	(5.3)
Interest Expense	(2.3)	(2.1)	(6.3)	(3.7)
Equity Earnings in ATC	0	0	0	0
Other Income (Expense)	2.1	0	4.1	(0.1)
Income (Loss) Before Income Taxes	(1.2)	(3.5)	(7.5)	(9.1)
Income Tax Expense (Benefit)	(1.8)	(3.6)	(6.2)	(9.2)
Net Income (Loss)	0.6	0.1	(1.3)	0.1
Total Assets	377.6	307.2	377.6	307.2
Property, Plant and Equipment - Net	72.0	59.1	72.0	59.1
Accumulated Depreciation	59.5	55.2	59.5	55.2
Capital Additions			$ 8.8	$ 5.7

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

9 Months Ended

12 Months Ended

Sep. 30, 2013

Dec. 31, 2012

Investments [Abstract]

ALLETE Properties

$ 91.2

$ 91.1

Available-for-sale Securities

16.1

^[1]

26.8

Cash Equivalents

31.2

20.7

Other

4.4

4.9

Total Other Investments

142.9

143.5

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

0.8

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

4.8

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

2.0

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

1.3

ALLETE Properties [Rollforward]

Land Inventory Beginning Balance

86.5

86.0

Cost of Sales

(0.2)

Other

0.2

0.7

Land Inventory Ending Balance

86.7

86.5

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

1.4

Other

3.1

3.2

Total Real Estate Assets

91.2

91.1

Impairment of Real Estate

Long-Term Finance Receivables, Allowance

$ 0.6

[1]	As of September 30, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.8 million, in one year to less than three years was $4.8 million, in three years to less than five years was $2.0 million, and in five or more years was $1.3 million.

Derivatives - Derivative (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Interest Rate Swap [Member]
Derivative [Line Items]
Interest Rate Swap Variable Rate Basis	one-month LIBOR
Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessments of hedge effectiveness resulted in no ineffectiveness recorded for the quarter and nine months ended September 30, 2013.
Interest Rate Swap Liability	$ 0.6	$ 0.7
Interest Rate Swap Liability, Other Non-Current Liabilities	0.2	0.7
Interest Rate Swap Liability, Other Current Liabilities	$ 0.4	$ 0
Interest Rate Swap Member Effective August 25, 2011 [Member]
Derivative [Line Items]
Interest Rate Swap Fixed Interest Rate	0.825%
Interest Rate Swap Member Effective August 26, 2014 [Member]
Derivative [Line Items]
Interest Rate Swap Fixed Interest Rate	0.75%

Fair Value - Recurring Fair Value Measures (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Investments [Abstract]
Cash Equivalents	$ 31.2		$ 20.7
Fair Value [Abstract]
Fair Value Activity in Level 3	0	0
Fair Value Hierarchy Transfers, All Levels	0	0
Recurring Fair Value Measurements [Member]
Investments [Abstract]
Available-for-sale - Equity Securities	7.2		18.0
Available-for-sale - Corporate Debt Securities	8.9		8.8
Cash Equivalents	31.2		20.7
Total Fair Value of Assets	47.3		47.5
Liabilities [Abstract]
Deferred Compensation	15.8		14.0
Derivatives - Interest Rate Swap	0.6		0.7
Total Fair Value of Liabilities	16.4		14.7
Total Net Fair Value of Assets (Liabilities)	30.9		32.8
Recurring Fair Value Measurements [Member] \| Level 1 [Member]
Investments [Abstract]
Available-for-sale - Equity Securities	7.2		18.0
Available-for-sale - Corporate Debt Securities	0		0
Cash Equivalents	31.2		20.7
Total Fair Value of Assets	38.4		38.7
Liabilities [Abstract]
Deferred Compensation	0		0
Derivatives - Interest Rate Swap	0		0
Total Fair Value of Liabilities	0		0
Total Net Fair Value of Assets (Liabilities)	38.4		38.7
Recurring Fair Value Measurements [Member] \| Level 2 [Member]
Investments [Abstract]
Available-for-sale - Equity Securities	0		0
Available-for-sale - Corporate Debt Securities	8.9		8.8
Cash Equivalents	0		0
Total Fair Value of Assets	8.9		8.8
Liabilities [Abstract]
Deferred Compensation	15.8		14.0
Derivatives - Interest Rate Swap	0.6		0.7
Total Fair Value of Liabilities	16.4		14.7
Total Net Fair Value of Assets (Liabilities)	(7.5)		(5.9)
Recurring Fair Value Measurements [Member] \| Level 3 [Member]
Investments [Abstract]
Available-for-sale - Equity Securities	0		0
Available-for-sale - Corporate Debt Securities	0		0
Cash Equivalents	0		0
Total Fair Value of Assets	0		0
Liabilities [Abstract]
Deferred Compensation	0		0
Derivatives - Interest Rate Swap	0		0
Total Fair Value of Liabilities	0		0
Total Net Fair Value of Assets (Liabilities)	$ 0		$ 0

Fair Value - Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,101.9	$ 1,018.1
Long-term Debt, Including Current Portion - Fair Value	$ 1,153.6	$ 1,143.7

- Definition

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

+ References+ Details

Regulatory Matters - Utility Rates (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013 Bison Wind Energy Center [Member] MW	Sep. 30, 2013 Bison 4 [Member] MW	Jun. 01, 2011 MPUC 2010 Minnesota Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Sep. 30, 2013 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Customers Years	Sep. 30, 2013 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Non-Affiliated Private Utility [Member] MW Years Customers	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Retail Customers [Member]	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Natural Gas Rates [Member] Retail Customers [Member]	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Water Rates [Member] Retail Customers [Member]
Rate Regulation [Line Items]
Approved Rate of Return on Common Equity			10.38%			10.90%
Approved Percentage of Capital Structure Related to Equity			54.29%
Number of Customers				16	1
Length of Notice Required to Terminate (in Years)				3	2
Average Monthly Demand (in MWs)					17
Approved Rate Increase or Decrease						2.40%	1.20%	(0.20%)	13.80%
Amount Of Estimated Additional Revenue						$ 1.7
Generating Capacity (MW)	292	205
Estimated Capital Expenditures		345
Capital Cost Spent to Date		$ 7.7

Regulatory Matters - The Patient Protection and Affordable Care Act of 2010 (PPACA) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended			3 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Jun. 30, 2011 Elimination of Medicare Part D [Member]	Dec. 31, 2010 Elimination of Medicare Part D [Member]
Unusual or Infrequent Item [Line Items]
Reversal of Previously Recorded Tax Benefit							$ 4.0
Deferred Income Tax Benefit	8.8	10.3	20.4	23.4		(2.9)
Non-Current Regulatory Assets	$ 340.3		$ 340.3		$ 340.3	$ 5.0

- Definition

Amount of deferred income tax expense (benefit) pertaining to income (loss) from continuing operations.

+ References+ Details

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

Sep. 30, 2013

Dec. 31, 2012

Regulatory Assets and Liabilities [Line Items]

Total Current Regulatory Assets

$ 22.8

^[1]

$ 22.5

^[1]

Non-Current Regulatory Assets

340.3

Total Regulatory Assets

363.1

362.8

Non-Current Regulatory Liabilities

68.7

60.1

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

17.7

19.5

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

20.4

18.1

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

17.7

15.5

Conservation Improvement Program [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

5.8

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

7.1

7.0

Deferred Fuel [Member]

Regulatory Assets and Liabilities [Line Items]

Total Current Regulatory Assets

22.8

^[1]

22.5

^[1]

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

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

247.0

260.7

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

34.4

36.0

Asset Retirement Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

14.9

12.1

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

35.5

^[2]

18.5

^[2]

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

5.0

Conservation Improvement Program [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

4.3

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

$ 3.5

$ 3.7

[1]	Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
[2]	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center.

Investment in ATC (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		9 Months Ended
	Oct. 31, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Investment in ATC [Abstract]
Ownership Percentage		8.00%		8.00%
Approved Return on Common Equity		12.20%		12.20%
Equity Method Investment, Expected Additional Investment		$ 0		$ 0
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2012	112.7			107.3
Cash Investments	0.8			2.3
Equity Earnings in ATC		4.9	4.9	15.1	14.3
Distributed ATC Earnings				(12.0)
Equity Investment Balance as of September 30, 2013		112.7		112.7
ATC Summarized Financial Data [Abstract]
Revenue		160.5	150.3	464.3	450.1
Operating Expense		77.6	68.8	217.2	210.1
Other Expense		20.2	21.0	62.6	62.1
Net Income		62.7	60.5	184.5	177.9
ALLETE's Equity in Net Income		$ 4.9	$ 4.9	$ 15.1	$ 14.3

Short-Term and Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended			0 Months Ended
	Apr. 02, 2013	Sep. 30, 2013	Dec. 31, 2012	Dec. 31, 2012 ALLETE Bonds 4.86% Series Due 2013 [Member]	Apr. 02, 2013 ALLETE Bonds 1.83% Due April 2018 [Member]	Apr. 02, 2013 ALLETE Bonds 3.30% Due October 2028 [Member]	Apr. 02, 2013 ALLETE Bonds 4.21% Due October 2043 [Member]	Aug. 26, 2013 ALLETE Amended Term Loan Variable Rate Due August 2015 [Member]	Aug. 26, 2013 ALLETE Amended Term Loan Variable Rate Due 2015 Effective August 26, 2013 [Member]	Aug. 26, 2013 ALLETE Amended Term Loan Variable Rate Due 2015 Effective August 26, 2014 [Member]
Financial Covenants [Abstract]
Required Indebtedness to Total Capital Ratio		0.65
Actual Indebtedness to Total Capital Ratio		0.46
Debt Instrument [Line Items]
Short-Term Debt Outstanding		$ 38.9	$ 84.5
Short-Term Debt Outstanding, Subsequently Matured		37.7	84.5	60.0
Long-Term Debt Outstanding		1,064.2	933.6
Proceeds from Issuance of First Mortgage Bonds	150.0				50.0	40.0	60.0
First Mortgage Bonds, Interest Rate					1.83%	3.30%	4.21%
Amended Term Loan, Principal Amount								$ 75.0
Amended Term Loan, Variable Rate Basis								one-month LIBOR
Amended Term Loan, Basis Spread on Variable Rate								0.875%
Amended Term Loan, Effective Interest Rate									1.70%	1.625%

Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 1.2	$ 1.5	$ 3.4	$ 3.4
Gain on Sale of Available-for-sale Securities	1.4	0	2.2	0
Investments and Other Income	0.7	0	1.9	0
Total Other Income	$ 3.3	$ 1.5	$ 7.5	$ 3.4

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

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Current Tax Expense (Benefit) [Abstract]

Federal

$ 0

^[1]

$ 0

^[1]

$ 0

^[1]

$ 0

^[1]

State

(0.1)

^[1]

(0.1)

^[1]

Total Current Tax Expense (Benefit)

(0.1)

Deferred Tax Expense (Benefit) [Abstract]

Federal

7.3

10.1

15.5

23.3

State

1.7

^[2]

0.4

^[2]

5.5

^[2]

0.7

^[2]

Investment Tax Credit Amortization

(0.2)

(0.6)

Total Deferred Tax Expense

8.8

10.3

20.4

23.4

Total Income Tax Expense

8.7

10.3

20.3

23.4

Effective Income Tax Rate

22.10%

25.50%

Federal Statutory Income Tax Rate

41.00%

Uncertain Tax Positions [Abstract]

Gross Unrecognized Tax Benefits

3.2

2.7

Unrecognized Tax Benefits that Would Favorably Impact Effective Tax Rate

$ 0.8

[1]	We incurred net operating losses (NOLs) due to the bonus depreciation provisions of the American Taxpayer Relief Act of 2012 and the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010 for the quarter and nine months ended September 30, 2013 and 2012. The 2013 and 2012 federal and state NOLs will be carried forward to offset future taxable income.
[2]	The quarter and nine months ended September 30, 2012 reflected increased state tax benefit from state renewable tax credits compared to the quarter and nine months ended September 30, 2013.

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

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2013

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

$ (21.3)

$ (21.0)

$ (22.0)

Other Comprehensive Income (Loss) Before Reclassifications

0.2

0.9

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

0.5

0.2

Net Other Comprehensive Income (Loss)

(0.3)

0.9

0.7

2.2

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(0.6)

(1.9)

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

0.1

^[1]

0.2

^[1]

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

(0.7)

^[1]

(2.1)

^[1]

Other Income (Expense) - Other [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

1.4

^[2]

2.2

^[2]

Income Tax Expense [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(0.6)

^[3]

(0.9)

^[3]

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

0.3

^[3]

0.8

^[3]

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

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

(0.5)

(0.1)

Other Comprehensive Income (Loss) Before Reclassifications

0.3

0.9

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

0.8

1.3

Net Other Comprehensive Income (Loss)

(0.5)

(0.4)

Defined Benefit Pension and Other Postretirement Items [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

(20.4)

(20.7)

(21.5)

Other Comprehensive Income (Loss) Before Reclassifications

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

(0.3)

(1.1)

Net Other Comprehensive Income (Loss)

0.3

1.1

Gains and Losses on Cash Flow Hedge [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Other Comprehensive Loss

(0.4)

(0.3)

(0.4)

Other Comprehensive Income (Loss) Before Reclassifications

(0.1)

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

Net Other Comprehensive Income (Loss)

$ (0.1)

$ 0

[1]	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense (See Note 13. Pension and Other Postretirement Benefit Plans)
[2]	Included in Other Income (Expense) – Other on the Consolidated Statement of Income.
[3]	Included in Income Tax Expense on the Consolidated Statement of Income.

Earnings Per Share and Common Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share and Common Stock [Abstract]
Anti-dilutive Shares Excluded from Diluted EPS Computation	0	200,000	0	200,000
Earnings Per Share - Basic [Abstract]
Net Income	$ 25.2	$ 29.4	$ 71.7	$ 68.2
Average Common Shares	39,800,000	37,700,000	39,400,000	37,300,000
Earnings Per Share	$ 0.63	$ 0.78	$ 1.82	$ 1.83
Earnings Per Share - Diluted [Abstract]
Net Income	$ 25.2	$ 29.4	$ 71.7	$ 68.2
Average Common Shares	39,900,000	37,800,000	39,500,000	37,300,000
Earnings Per Share	$ 0.63	$ 0.78	$ 1.81	$ 1.83
Dilutive Securities (Shares)	100,000	100,000	100,000	0

Pension and Other Postretirement Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	$ 2.4	$ 2.3	$ 7.4	$ 6.9
Interest Cost	6.5	6.6	19.5	19.8
Expected Return on Plan Assets	(8.8)	(8.9)	(26.4)	(26.6)
Amortization of Prior Service Costs	0.1	0	0.2	0.2
Amortization of Net Loss	5.4	4.4	16.1	13.1
Amortization of Transition Obligation			0	0
Net Periodic Benefit Expense	5.6	4.4	16.8	13.4
Contributions			0	0
Estimated Future Contributions			0
Other Postretirement [Member]
Components of Net Periodic Benefit Expense [Abstract]
Service Cost	0.9	1.0	2.9	3.1
Interest Cost	1.7	2.4	5.1	7.1
Expected Return on Plan Assets	(2.4)	(2.5)	(7.3)	(7.5)
Amortization of Prior Service Costs	(0.6)	(0.4)	(1.9)	(1.3)
Amortization of Net Loss	0.4	1.9	1.2	5.7
Amortization of Transition Obligation			0	0.1
Net Periodic Benefit Expense	0	2.4	0	7.2
Contributions			10.8	0
Estimated Future Contributions			$ 0

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Debt Outstanding	$ 404,400,000
Annual Debt Service	44,000,000
Power Purchased Under Long-term Contracts	51,300,000	48,700,000
Interest Expense	7,900,000	8,300,000
Square Butte PPA [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Capacity (MW)	455
Output Entitlement	50.00%
Minnkota PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Oliver Wind I PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Term of Contract (Years)	25
Fixed Capacity Charges	0
Oliver Wind II PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Term of Contract (Years)	25
Fixed Capacity Charges	$ 0
Manitoba Hydro PPA (expires April 2015) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro PPA (expires April 2022) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh)	1,000,000
Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Term of Contract (Years)	15

Commitments, Guarantees and Contingencies - North Dakota Wind Development (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013 kV Miles
DC Transmission Line from Square Butte [Member]
North Dakota Wind Development [Line Items]
Transmission Line Length (Miles)	465
Transmission Line Capacity (kV)	250
Bison Wind Energy Center [Member]
North Dakota Wind Development [Line Items]
Generating Capacity (MW)	292
Bison 4 [Member]
North Dakota Wind Development [Line Items]
Generating Capacity (MW)	205
Estimated Capital Expenditures	$ 345
Capital Cost Spent to Date	$ 7.7

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) (Coal and Transportation [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Coal and Transportation [Member]
Coal, Rail and Shipping Contracts [Line Items]
Minimum Annual Payment Obligation, Current Year	$ 12.1
Minimum Annual Payment Obligation, Year Two	6.9
Minimum Annual Payment Obligation, Year Three	$ 2.2

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Leasing Agreements [Line Items]
Operating Leases, Future Minimum Payments, Due in Current Year	$ 11.5
Operating Leases, Future Minimum Payments, Due in Year Two	11.7
Operating Leases, Future Minimum Payments, Due in Year Three	11.4
Operating Leases, Future Minimum Payments, Due in Year Four	9.3
Operating Leases, Future Minimum Payments, Due in Year Five	8.5
Operating Leases, Future Minimum Payments, Due Thereafter	35.0
BNI Coal Dragline Lease [Member]
Leasing Agreements [Line Items]
Termination Fee	3.0
Operating Leases, Future Minimum Payments, Due in Current Year	$ 2.8

Commitments, Guarantees and Contingencies - Transmission (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	3
Capital Cost Spent to Date	$ 70.9	$ 48.2
CapX2020 [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	100
CapX2020 [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	110
CapX2020 Fargo to Monticello Projects [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	238
Transmission Line Capacity (kV)	345
Capital Cost Spent to Date	60.0	37.3
CapX2020 Monticello to St. Cloud Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	28
Transmission Line Capacity (kV)	345
CapX2020 Bemidji to Grand Rapids Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	70
Transmission Line Capacity (kV)	230
Capital Cost Spent to Date	10.9	10.9
Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	240
Transmission Line Capacity (kV)	500
Great Northern Transmission Line [Member] \| Minnesota Power [Member]
Transmission [Line Items]
Ownership of GNTL	51.00%
Great Northern Transmission Line [Member] \| Manitoba Hydro [Member]
Transmission [Line Items]
Ownership of GNTL	49.00%
Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	200
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	$ 300

Commitments, Guarantees and Contingencies - Other Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013 Years	Dec. 31, 2012
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Surety Bond Amount	$ 29.7
Reclamation Letter of Credit	2.6
Total Current Estimated Reclamation Liability	32.3
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Surety Bond and Letters of Credit	10.2
Development and Maintenance Obligations	7.4
Town Center Community Development District [Member]
Guarantor Obligations [Line Items]
Bond Amount	26.4
Bond Interest Rate	6.00%
Bond Term (Years)	31
Ownership of Property Benefited	73.00%	73.00%
Annual Assessment	1.4
Palm Coast Park Community Development District [Member]
Guarantor Obligations [Line Items]
Bond Amount	31.8
Bond Interest Rate	5.70%
Bond Term (Years)	31
Ownership of Property Benefited	93.00%	93.00%
Annual Assessment	$ 2.1

Derivatives - Hedged Item (Details) (Term Loan [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Term Loan [Member]
Debt Instrument [Line Items]
Term Loan Principal Amount	$ 75.0
Percentage of Debt Hedged by Interest Rate Derivatives	7.00%

Regulatory Matters - Boswell Mercury Emissions Reduction Plan (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 350

Commitments, Guarantees and Contingencies - Environmental Matters (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 350

Commitments, Guarantees and Contingencies - Legal Proceedings (Details) (Pending Litigation [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Pending Litigation [Member]
Legal Proceedings [Line Items]
Damages Sought	$ 20.0

Investments - Parentheticals (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Investments Parentheticals [Abstract]
Long-Term Finance Receivables, Allowance	$ 0.6	$ 0.6