Total Liabilities and Equity

(21.0)

^[1]

(22.0)

^[1]

Retained Earnings

467.9

459.6

Total Equity

1,249.0

1,201.0

$ 3,350.9

$ 3,253.4

[1]	Amounts shown are net of tax.

Consolidated Balance Sheet Parentheticals (USD $) In Millions, except Per Share data, unless otherwise specified	Jun. 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	40.1	39.4

Consolidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Operating Revenue	$ 235.6	$ 216.4	$ 499.4	$ 456.4
Operating Expenses [Abstract]
Fuel and Purchased Power	78.7	72.1	165.2	149.2
Operating and Maintenance	103.8	96.2	208.5	196.1
Depreciation	28.7	24.8	56.9	49.4
Total Operating Expenses	211.2	193.1	430.6	394.7
Operating Income	24.4	23.3	68.8	61.7
Other Income (Expense) [Abstract]
Interest Expense	(12.8)	(10.1)	(25.1)	(21.1)
Equity Earnings in ATC	5.0	4.8	10.2	9.4
Other	1.5	1.2	4.2	1.9
Total Other Expense	(6.3)	(4.1)	(10.7)	(9.8)
Income Before Income Taxes	18.1	19.2	58.1	51.9
Income Tax Expense	4.1	4.8	11.6	13.1
Net Income	$ 14.0	$ 14.4	$ 46.5	$ 38.8
Average Shares of Common Stock [Abstract]
Basic	39.4	37.3	39.2	37.0
Diluted	39.6	37.4	39.3	37.1
Basic Earnings Per Share of Common Stock	$ 0.36	$ 0.39	$ 1.19	$ 1.05
Diluted Earnings Per Share of Common Stock	$ 0.35	$ 0.39	$ 1.18	$ 1.05
Dividends Per Share of Common Stock	$ 0.475	$ 0.46	$ 0.95	$ 0.92

Consolidated Statement of Comprehensive Income (USD $)
In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Comprehensive Income (Loss) [Abstract]

Net Income

$ 14.0

$ 14.4

$ 46.5

$ 38.8

Other Comprehensive Income (Loss) [Abstract]

Unrealized Gain (Loss) on Securities, Net of Income Taxes of $0.1, $(0.5), $0.1 and $0.2

0.1

(0.5)

0.1

0.5

Unrealized Gain (Loss) on Derivatives, Net of Income Taxes of $0.1, $-, $0.1 and $(0.1)

(0.1)

0.1

(0.2)

Defined Benefit Pension and Other Postretirement Benefit Plans, Net of Income Taxes of $0.3, $0.4, $0.5 and $0.7

0.5

0.8

1.0

Total Other Comprehensive Income (Loss)

0.6

^[1]

(0.1)

1.0

^[1]

1.3

Comprehensive Income

$ 14.6

$ 14.3

$ 47.5

$ 40.1

[1]	Amounts shown are net of tax.

Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain (Loss) on Securities, Tax	$ 0.1	$ (0.5)	$ 0.1	$ 0.2
Unrealized Gain (Loss) on Derivatives, Tax	0.1	0	0.1	(0.1)
Defined Benefit Pension and Other Postretirement Benefit Plans, Tax	$ 0.3	$ 0.4	$ 0.5	$ 0.7

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Operating Activities [Abstract]
Net Income	$ 46.5	$ 38.8
Allowance for Funds Used During Construction - Equity	(2.1)	(1.9)
Income from Equity Investments, Net of Dividends	(2.3)	(1.7)
Gain on Sale of Assets	(0.1)	0
Gain on Sale of Investments	(0.8)	0
Depreciation Expense	56.9	49.4
Amortization of Debt Issuance Costs	0.5	0.5
Deferred Income Tax Expense	11.6	13.1
Share-Based Compensation Expense	1.3	1.2
ESOP Compensation Expense	4.0	3.7
Defined Benefit Pension and Postretirement Benefit Expense	11.2	13.8
Bad Debt Expense	0.4	0.5
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	9.9	12.4
Inventories	(1.2)	(0.2)
Prepayments and Other	7.4	1.6
Accounts Payable	(10.1)	(8.2)
Other Current Liabilities	(5.8)	0
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans	(10.8)	0
Changes in Regulatory and Other Non-Current Assets	(8.0)	(1.8)
Changes in Regulatory and Other Non-Current Liabilities	2.6	6.9
Cash from Operating Activities	111.1	128.1
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	8.1	1.0
Payments for Purchase of Available-for-sale Securities	(1.4)	(1.0)
Investment in ATC	(1.6)	(2.0)
Changes to Other Investments	(2.6)	(3.2)
Additions to Property, Plant and Equipment	(128.6)	(221.8)
Proceeds from Sale of Assets	0.9	0
Cash for Investing Activities	(125.2)	(227.0)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	33.3	30.5
Proceeds from Issuance of Long-Term Debt	150.0	15.6
Payments for Notes Payable	0	(1.1)
Payments for Long-Term Debt	(65.5)	(3.1)
Debt Issuance Costs	(1.3)	0
Dividends on Common Stock	(38.2)	(35.5)
Cash from Financing Activities	78.3	6.4
Change in Cash and Cash Equivalents	64.2	(92.5)
Cash and Cash Equivalents at Beginning of Period	80.8	101.1
Cash and Cash Equivalents at End of Period	$ 145.0	$ 8.6

Operations and Significant Accounting Policies

6 Months Ended

Jun. 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	June 30, 2013		December 31, 2012
Millions
Fuel		$25.3		$28.0
Materials and Supplies	45.7		41.8
Total Inventories		$71.0		$69.8



Prepayments and Other Current Assets	June 30, 2013		December 31, 2012
Millions
Deferred Fuel Adjustment Clause		$18.3		$22.5
Other	7.9		11.1
Total Prepayments and Other Current Assets		$26.2		$33.6



Other Current Liabilities	June 30, 2013		December 31, 2012
Millions
Customer Deposits		$29.1		$28.8
Other	31.7		33.8
Total Other Current Liabilities		$60.8		$62.6



Other Non-Current Liabilities	June 30, 2013		December 31, 2012
Millions
Asset Retirement Obligation		$81.6		$77.9
Other	47.7		45.4
Total Other Non-Current Liabilities		$129.3		$123.3

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flows Information.



For the Six Months Ended June 30,	2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$22.8		$21.7
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		$28.2		$14.8
Capitalized Asset Retirement Costs		$1.9		$2.4
AFUDC – Equity		$2.1		$1.9

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 was adopted beginning with the quarter ended March 31, 2013, and required additional disclosures but 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).)

Business Segments

6 Months Ended

Jun. 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 June 30, 2013
Operating Revenue		$235.6			$215.8			$19.8
Fuel and Purchased Power Expense	78.7			78.7			—
Operating and Maintenance Expense	103.8			82.8			21.0
Depreciation Expense	28.7			27.1			1.6
Operating Income (Loss)	24.4			27.2			(2.8		)
Interest Expense	(12.8		)	(10.4		)	(2.4		)
Equity Earnings in ATC	5.0			5.0			—
Other Income	1.5			1.1			0.4
Income (Loss) Before Income Taxes	18.1			22.9			(4.8		)
Income Tax Expense (Benefit)	4.1			6.6			(2.5		)
Net Income (Loss)		$14.0			$16.3		$(2.3)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended June 30, 2012
Operating Revenue		$216.4			$197.0			$19.4
Fuel and Purchased Power Expense	72.1			72.1			—
Operating and Maintenance Expense	96.2			76.1			20.1
Depreciation Expense	24.8			23.4			1.4
Operating Income (Loss)	23.3			25.4			(2.1		)
Interest Expense	(10.1		)	(9.9		)	(0.2		)
Equity Earnings in ATC	4.8			4.8			—
Other Income	1.2			1.2			—
Income (Loss) Before Income Taxes	19.2			21.5			(2.3		)
Income Tax Expense (Benefit)	4.8			7.1			(2.3		)
Net Income		$14.4			$14.4		—



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2013
Operating Revenue		$499.4			$457.2			$42.2
Fuel and Purchased Power Expense	165.2			165.2			—
Operating and Maintenance Expense	208.5			165.0			43.5
Depreciation Expense	56.9			53.9			3.0
Operating Income (Loss)	68.8			73.1			(4.3		)
Interest Expense	(25.1		)	(21.1		)	(4.0		)
Equity Earnings in ATC	10.2			10.2			—
Other Income	4.2			2.2			2.0
Income (Loss) Before Income Taxes	58.1			64.4			(6.3		)
Income Tax Expense (Benefit)	11.6			16.0			(4.4		)
Net Income (Loss)		$46.5			$48.4		$(1.9)

As of June 30, 2013
Total Assets		$3,350.9			$2,997.0			$353.9
Property, Plant and Equipment – Net		$2,397.2			$2,329.6			$67.6
Accumulated Depreciation		$1,202.8			$1,143.2			$59.6
Capital Additions		$100.2			$97.2			$3.0



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2012
Operating Revenue		$456.4			$415.6			$40.8
Fuel and Purchased Power Expense	149.2			149.2			—
Operating and Maintenance Expense	196.1			154.2			41.9
Depreciation Expense	49.4			46.6			2.8
Operating Income (Loss)	61.7			65.6			(3.9		)
Interest Expense	(21.1		)	(19.5		)	(1.6		)
Equity Earnings in ATC	9.4			9.4			—
Other Income (Expense)	1.9			2.0			(0.1		)
Income (Loss) Before Income Taxes	51.9			57.5			(5.6		)
Income Tax Expense (Benefit)	13.1			18.7			(5.6		)
Net Income		$38.8			$38.8		—

As of June 30, 2012
Total Assets		$2,962.2			$2,755.4			$206.8
Property, Plant and Equipment – Net		$2,177.5			$2,119.9			$57.6
Accumulated Depreciation		$1,124.5			$1,070.1			$54.4
Capital Additions		$235.1			$232.3			$2.8

Investments

6 Months Ended

Jun. 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	June 30, 2013		December 31, 2012
Millions
ALLETE Properties		$91.1		$91.1
Available-for-sale Securities (a)	20.4		26.8
Cash Equivalents	24.4		20.7
Other	4.3		4.9
Total Other Investments		$140.2		$143.5


(a)	As of June 30, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $1.2 million, in one year to less than three years was $5.1 million, in three years to less than five years was $1.3 million, and in five or more years was $0.9 million.



ALLETE Properties	June 30, 2013		December 31, 2012
Millions
Land Inventory Beginning Balance		$86.5		$86.0
Deeds to Collateralized Property	—		0.5
Cost of Sales	—		(0.2		)
Capitalized Improvements and Other	0.1		0.2
Land Inventory Ending Balance	86.6		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		$91.1		$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 six months ended June 30, 2013 (none for the year ended December 31, 2012).

Long-Term Finance Receivables. As of June 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 June 30, 2013, we had an allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2012).

Derivatives	6 Months Ended
Derivatives	Jun. 30, 2013
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 7 percent of the Company’s outstanding long-term debt as of June 30, 2013. (See Note 8. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting with respect to that derivative. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in the value of the Swap are deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the quarter and six months ended June 30, 2013. The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of June 30, 2013, the fair value of the Swap was a $0.5 million liability (a $0.7 million liability as of December 31, 2012) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

Fair Value

6 Months Ended

Jun. 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.

NOTE 5. FAIR VALUE (Continued)

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 June 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 are excluded from the recurring fair value measures in the tables below.



	Fair Value as of June 30, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$11.9	—		—		$11.9
Available-for-sale – Corporate Debt Securities	—			$8.5	—	8.5
Cash Equivalents	24.4		—		—	24.4
Total Fair Value of Assets		$36.3		$8.5	—		$44.8

Liabilities:
Deferred Compensation	—			$15.7	—		$15.7
Derivatives – Interest Rate Swap	—		0.5		—	0.5
Total Fair Value of Liabilities	—			$16.2	—		$16.2

Total Net Fair Value of Assets (Liabilities)		$36.3	$(7.7)		—		$28.6



	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 six months ended June 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 six months ended June 30, 2013 and 2012 , there were no transfers in or out of Levels 1, 2 or 3.

NOTE 5. FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the item listed in the table below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item 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
June 30, 2013	$1,102.6	$1,160.2
December 31, 2012	$1,018.1	$1,143.7

Regulatory Matters

6 Months Ended

Jun. 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 desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. In January 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). In February 2012, the Court granted the petition for review and oral arguments were held before the Court in October 2012. A decision is expected in the third quarter of 2013. We cannot predict the outcome at this time.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. Minnesota Power’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 17MW 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 Riders. 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 that includes additional transmission expenditures, which is expected to be approved in the second half of 2013.

NOTE 6. REGULATORY MATTERS (Continued)

Renewable Cost Recovery Riders. The Bison Wind Energy Center in North Dakota consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for Bison were approved by the MPUC in a November 2011 order and are based on investments and expenditures through that period. 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 2011, which is expected to be approved in the second half of 2013.

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 is also subject to MPUC approval. We expect a decision from the MPUC on these filings in late 2013.

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

Integrated Resource Plan. In May 2011, the MPUC issued its final order approving our 2010 Integrated Resource Plan. As a condition of the final order, a required baseload diversification study evaluating the impact of additional environmental regulations over the next two decades was filed in February 2012. Minnesota Power’s 2013 Integrated Resource Plan, filed on March 1, 2013, 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. A decision by the MPUC on this plan is expected in late 2013.

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 between $350 million and $400 million. The MPCA issued its report on March 1, 2013, in support of the Boswell Unit 4 mercury emissions reduction plan stating that the plan is appropriate for accomplishing the objectives of reducing emissions of mercury and other pollutants under the Minnesota Statutes and recommended that the MPUC accept the report’s findings. We expect a decision by the MPUC on the plan in the third quarter of 2013. Upon approval by the MPUC, we anticipate filing a petition to include investments and expenditures in customer billing rates.

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.

NOTE 6. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	June 30, 2013		December 31, 2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$18.3		$22.5
Total Current Regulatory Assets	18.3		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	251.5		260.7
Income Taxes	34.3		36.0
Asset Retirement Obligation	13.9		12.1
Cost Recovery Riders (b)	29.2		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.6		3.7
Total Non-Current Regulatory Assets	337.5		340.3

Total Regulatory Assets		$355.8		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.7		$19.5
Plant Removal Obligations	19.3		18.1
Wholesale and Retail Contra AFUDC	16.7		15.5
Conservation Improvement Program	2.7		—
Other	6.7		7.0
Total Non-Current Regulatory Liabilities		$63.1		$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 Bison.

Investment in ATC

6 Months Ended

Jun. 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 June 30, 2013, our equity investment in ATC was $111.2 million ($107.3 million at December 31, 2012). In the first six months of 2013, we invested $1.6 million in ATC, and on July 30, 2013, we invested an additional $0.8 million. We expect to make additional investments of approximately $0.7 million in 2013.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2012		$107.3
Cash Investments	1.6
Equity in ATC Earnings	10.2
Distributed ATC Earnings	(7.9		)
Equity Investment Balance as of June 30, 2013		$111.2

NOTE 7. INVESTMENT IN ATC (Continued)

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



	Quarter Ended			Six Months Ended
ATC Summarized Financial Data	June 30,			June 30,
Income Statement Data	2013		2012	2013		2012
Millions
Revenue		$152.1	$152.2		$303.9		$299.8
Operating Expense	69.9		71.8	139.7		141.3
Other Expense	20.9		21.1	42.4		41.1
Net Income		$61.3	$59.3		$121.8		$117.4
ALLETE’s Equity in Net Income		$5.0	$4.8		$10.2		$9.4

Short-Term and Long-Term Debt

6 Months Ended

Jun. 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 June 30, 2013, total short-term debt outstanding was $37.9 million ($84.5 million as of December 31, 2012) and consisted of long-term debt due within one year. 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 June 30, 2013, total long-term debt outstanding was $1,064.7 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.

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 June 30, 2013, our ratio was approximately 0.47 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from 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 June 30, 2013, ALLETE was in compliance with its financial covenants.

Income Tax Expense

6 Months Ended

Jun. 30, 2013

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Millions
Current Tax Expense (Benefit)
Federal (a)	$(0.2)			—			—			—
State (a)	—			—			—			—
Total Current Tax Expense (Benefit)	(0.2		)	—			—			—
Deferred Tax Expense (Benefit)
Federal	3.6				$4.8			$8.2			$13.2
State (b)	0.9			0.2			3.8			0.3
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Total Deferred Tax Expense	4.3			4.8			11.6			13.1
Total Income Tax Expense		$4.1			$4.8			$11.6			$13.1


(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 six months ended June 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 six months ended June 30, 2012, reflected increased state tax benefit from state renewable tax credits compared to the quarter and six months ended June 30, 2013.

For the six months ended June 30, 2013, the effective tax rate was 20.0 percent (25.2 percent for the six months ended June 30, 2012). The decrease from the effective tax rate for the six months ended June 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 June 30, 2013, we had gross unrecognized tax benefits of $2.6 million ($2.7 million as of December 31, 2012). Of the total gross unrecognized tax benefits, $0.7 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 substantially all of the unrecognized tax benefits as of June 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.

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 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 by Component



	Unrealized Gains and Losses on Available-for-sale Securities (a)		Defined Benefit Pension, Other Postretirement Items (a)		Gains and Losses on Cash Flow Hedge (a)	Total (a)
Millions
For the Quarter Ended June 30, 2013
Beginning Balance	$(0.1)		$(21.2)		$(0.3)	$(21.6)
Other Comprehensive Income (Loss) Before Reclassifications	0.1		(2.6	)	—	(2.5	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		3.1		—	3.1
Net Other Comprehensive Income	0.1		0.5		—	0.6
Ending Balance	—		$(20.7)		$(0.3)	$(21.0)

For the Six Months Ended June 30, 2013
Beginning Balance	$(0.1)		$(21.5)		$(0.4)	$(22.0)
Other Comprehensive Income (Loss) Before Reclassifications	0.6		(5.5	)	0.1	(4.8	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.5	)	6.3		—	5.8
Net Other Comprehensive Income	0.1		0.8		0.1	1.0
Ending Balance	—		$(20.7)		$(0.3)	$(21.0)


(a)	Amounts shown are net of tax.

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

Reclassifications Out of Accumulated Other Comprehensive Loss



Details About Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss (a)			Affected Income Statement Line Item
Millions
For the Quarter Ended June 30, 2013
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs		$0.7		(b)
Actuarial Gains and Losses	(5.8		)	(b)
	(5.1		)
	2.0			Income Tax Expense
	$(3.1)
Total Reclassifications	$(3.1)

For the Six Months Ended June 30, 2013
Unrealized Gains on Available-for-sale Securities		$0.8		Other Income (Expense) - Other
	(0.3		)	Income Tax Expense
		$0.5

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs		$1.2		(b)
Actuarial Gains and Losses	(11.5		)	(b)
	(10.3		)
	4.0			Income Tax Expense
	$(6.3)
Total Reclassifications	$(5.8)


(a)	Amounts in parentheses indicate charges to net income.


(b)	These components of accumulated other comprehensive loss are included in the computation of net pension and other postretirement benefit expense. (See Note 13. Pension and Other Postretirement Benefit Plans.)

Earnings Per Share and Common Stock

6 Months Ended

Jun. 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 six months ended June 30, 2013 and 2012, zero and 0.3 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 June 30,
Net Income		$14.0			$14.0		$14.4			$14.4
Average Common Shares	39.4		0.2	39.6		37.3		0.1	37.4
Earnings Per Share		$0.36			$0.35		$0.39			$0.39
For the Six Months Ended June 30,
Net Income		$46.5			$46.5		$38.8			$38.8
Average Common Shares	39.2		0.1	39.3		37.0		0.1	37.1
Earnings Per Share		$1.19			$1.18		$1.05			$1.05

Pension and Other Postretirement Benefit Plans

6 Months Ended

Jun. 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 June 30,
Service Cost		$2.5			$2.3			$1.0			$1.1
Interest Cost	6.5			6.6			1.7			2.3
Expected Return on Plan Assets	(8.8		)	(8.9		)	(2.4		)	(2.5		)
Amortization of Prior Service Costs	—			0.1			(0.7		)	(0.5		)
Amortization of Net Loss	5.4			4.4			0.4			1.9
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$5.6			$4.5		—				$2.4

For the Six Months Ended June 30,
Service Cost		$5.0			$4.6			$2.0			$2.1
Interest Cost	13.0			13.2			3.4			4.7
Expected Return on Plan Assets	(17.6		)	(17.7		)	(4.9		)	(5.0		)
Amortization of Prior Service Costs	0.1			0.2			(1.3		)	(0.9		)
Amortization of Net Loss	10.7			8.7			0.8			3.8
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$11.2			$9.0		—				$4.8

Employer Contributions. For the six months ended June 30, 2013, no contributions were made to our defined benefit pension plan (none for the six months ended June 30, 2012). For the six months ended June 30, 2013, we contributed $10.8 million to our other postretirement benefit plan (none for the six months ended June 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

6 Months Ended

Jun. 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 June 30, 2013, Square Butte had total debt outstanding of $404.9 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.

Minnesota Power’s cost of power purchased from Square Butte during the six months ended June 30, 2013 was $33.0 million ($33.0 million for the six months ended June 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 $5.3 million during the six months ended June 30, 2013 ($5.6 million for the six months ended June 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 by the end of 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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for 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.

In February 2012, Minnesota Power and Manitoba Hydro proposed construction of the Great Northern Transmission Line, a 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, which is targeted to be in service in 2020. Total project cost and cost allocations are still to be determined; however, at this time we expect our capital expenditures to range between $200 million and $400 million. The Great Northern Transmission Line is subject to various federal and state regulatory approvals. In addition, Manitoba Hydro must obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada.

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 2014. 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 $22.4 million for the remainder of 2013 and $1.0 million for 2014. 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. This includes the CapX2020 initiative, investments in our own transmission assets, investments in other regional transmission assets (individually or in combination with others), and our investment in ATC.

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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

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 $59.8 million was spent through June 30, 2013, of which $48.9 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.

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 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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 due to the August 2012 District of Columbia Circuit Court of Appeals decision.

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. It is uncertain what controls would ultimately be required at Taconite Harbor Unit 3 under this scenario. On January 30, 2013, Minnesota Power announced its “EnergyForward” strategic plan, which includes retiring Taconite Harbor Unit 3 in 2015, subject to MPUC approval.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 totaling between $350 million and $400 million through 2016. Our “EnergyForward” plan 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. Costs for complying with the final rule cannot be estimated at this time.

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 above.

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with 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.

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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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.

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 require the EPA to evaluate modeling data to determine attainment. The EPA notified states that their SIPs for attainment of the standard were required to be submitted to the EPA for approval by June 2013, but the evaluation of modeling data will not be required until 2017.

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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 apply only to new or re-powered units and were open for public comment through June 25, 2012. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. The CAP described above directs the EPA to re-propose the rule by September 20, 2013. The CAP also directs the EPA 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. Under the CAP, the EPA will issue regulatory guidelines and objectives to the states, which in turn will submit SIPs for EPA approval that demonstrate how the state will meet or surpass achievement of the EPA targeted objectives. The CAP directs the EPA to require states to submit such SIPs by June 30, 2016.

Minnesota has already initiated several measures consistent with those called for under the CAP. Minnesota Power has also announced its “EnergyForward” 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 District Court for the District of Columbia 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. Comments on the permitting guidance were submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

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

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA 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, with public comments due 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.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its coal-fired electric generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. In June 2010, the EPA proposed regulations for coal combustion residuals 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 June 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 June 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 June 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. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of June 30, 2013, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance limits for any potential loss. Our insurance carrier is providing a defense subject to a reservation of rights as to certain claims.

NOTE 14. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

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 June 30, 2013, because a potential loss is not currently probable or reasonably estimable.

Other. We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. 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)	6 Months Ended
	Jun. 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 was adopted beginning with the quarter ended March 31, 2013, and required additional disclosures but 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).)
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]	Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.
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)

6 Months Ended

Jun. 30, 2013

Operations and Significant Accounting Policies [Abstract]

Inventories [Table Text Block]



Inventories	June 30, 2013		December 31, 2012
Millions
Fuel		$25.3		$28.0
Materials and Supplies	45.7		41.8
Total Inventories		$71.0		$69.8

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	June 30, 2013		December 31, 2012
Millions
Deferred Fuel Adjustment Clause		$18.3		$22.5
Other	7.9		11.1
Total Prepayments and Other Current Assets		$26.2		$33.6

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



Other Current Liabilities	June 30, 2013		December 31, 2012
Millions
Customer Deposits		$29.1		$28.8
Other	31.7		33.8
Total Other Current Liabilities		$60.8		$62.6



Other Non-Current Liabilities	June 30, 2013		December 31, 2012
Millions
Asset Retirement Obligation		$81.6		$77.9
Other	47.7		45.4
Total Other Non-Current Liabilities		$129.3		$123.3

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



For the Six Months Ended June 30,	2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$22.8		$21.7
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		$28.2		$14.8
Capitalized Asset Retirement Costs		$1.9		$2.4
AFUDC – Equity		$2.1		$1.9

Business Segments (Tables)

6 Months Ended

Jun. 30, 2013

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended June 30, 2013
Operating Revenue		$235.6			$215.8			$19.8
Fuel and Purchased Power Expense	78.7			78.7			—
Operating and Maintenance Expense	103.8			82.8			21.0
Depreciation Expense	28.7			27.1			1.6
Operating Income (Loss)	24.4			27.2			(2.8		)
Interest Expense	(12.8		)	(10.4		)	(2.4		)
Equity Earnings in ATC	5.0			5.0			—
Other Income	1.5			1.1			0.4
Income (Loss) Before Income Taxes	18.1			22.9			(4.8		)
Income Tax Expense (Benefit)	4.1			6.6			(2.5		)
Net Income (Loss)		$14.0			$16.3		$(2.3)



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Quarter Ended June 30, 2012
Operating Revenue		$216.4			$197.0			$19.4
Fuel and Purchased Power Expense	72.1			72.1			—
Operating and Maintenance Expense	96.2			76.1			20.1
Depreciation Expense	24.8			23.4			1.4
Operating Income (Loss)	23.3			25.4			(2.1		)
Interest Expense	(10.1		)	(9.9		)	(0.2		)
Equity Earnings in ATC	4.8			4.8			—
Other Income	1.2			1.2			—
Income (Loss) Before Income Taxes	19.2			21.5			(2.3		)
Income Tax Expense (Benefit)	4.8			7.1			(2.3		)
Net Income		$14.4			$14.4		—



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2013
Operating Revenue		$499.4			$457.2			$42.2
Fuel and Purchased Power Expense	165.2			165.2			—
Operating and Maintenance Expense	208.5			165.0			43.5
Depreciation Expense	56.9			53.9			3.0
Operating Income (Loss)	68.8			73.1			(4.3		)
Interest Expense	(25.1		)	(21.1		)	(4.0		)
Equity Earnings in ATC	10.2			10.2			—
Other Income	4.2			2.2			2.0
Income (Loss) Before Income Taxes	58.1			64.4			(6.3		)
Income Tax Expense (Benefit)	11.6			16.0			(4.4		)
Net Income (Loss)		$46.5			$48.4		$(1.9)

As of June 30, 2013
Total Assets		$3,350.9			$2,997.0			$353.9
Property, Plant and Equipment – Net		$2,397.2			$2,329.6			$67.6
Accumulated Depreciation		$1,202.8			$1,143.2			$59.6
Capital Additions		$100.2			$97.2			$3.0



	Consolidated			Regulated Operations			Investments and Other
Millions
For the Six Months Ended June 30, 2012
Operating Revenue		$456.4			$415.6			$40.8
Fuel and Purchased Power Expense	149.2			149.2			—
Operating and Maintenance Expense	196.1			154.2			41.9
Depreciation Expense	49.4			46.6			2.8
Operating Income (Loss)	61.7			65.6			(3.9		)
Interest Expense	(21.1		)	(19.5		)	(1.6		)
Equity Earnings in ATC	9.4			9.4			—
Other Income (Expense)	1.9			2.0			(0.1		)
Income (Loss) Before Income Taxes	51.9			57.5			(5.6		)
Income Tax Expense (Benefit)	13.1			18.7			(5.6		)
Net Income		$38.8			$38.8		—

As of June 30, 2012
Total Assets		$2,962.2			$2,755.4			$206.8
Property, Plant and Equipment – Net		$2,177.5			$2,119.9			$57.6
Accumulated Depreciation		$1,124.5			$1,070.1			$54.4
Capital Additions		$235.1			$232.3			$2.8

Investments (Tables)

6 Months Ended

Jun. 30, 2013

Investments [Abstract]

Other Investments and ALLETE Properties [Table Text Block]



Other Investments	June 30, 2013		December 31, 2012
Millions
ALLETE Properties		$91.1		$91.1
Available-for-sale Securities (a)	20.4		26.8
Cash Equivalents	24.4		20.7
Other	4.3		4.9
Total Other Investments		$140.2		$143.5


(a)	As of June 30, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $1.2 million, in one year to less than three years was $5.1 million, in three years to less than five years was $1.3 million, and in five or more years was $0.9 million.



ALLETE Properties	June 30, 2013		December 31, 2012
Millions
Land Inventory Beginning Balance		$86.5		$86.0
Deeds to Collateralized Property	—		0.5
Cost of Sales	—		(0.2		)
Capitalized Improvements and Other	0.1		0.2
Land Inventory Ending Balance	86.6		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		$91.1		$91.1

Fair Value (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of June 30, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale – Equity Securities		$11.9	—		—		$11.9
Available-for-sale – Corporate Debt Securities	—			$8.5	—	8.5
Cash Equivalents	24.4		—		—	24.4
Total Fair Value of Assets		$36.3		$8.5	—		$44.8

Liabilities:
Deferred Compensation	—			$15.7	—		$15.7
Derivatives – Interest Rate Swap	—		0.5		—	0.5
Total Fair Value of Liabilities	—			$16.2	—		$16.2

Total Net Fair Value of Assets (Liabilities)		$36.3	$(7.7)		—		$28.6



	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
June 30, 2013	$1,102.6	$1,160.2
December 31, 2012	$1,018.1	$1,143.7

Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2013

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	June 30, 2013		December 31, 2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$18.3		$22.5
Total Current Regulatory Assets	18.3		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	251.5		260.7
Income Taxes	34.3		36.0
Asset Retirement Obligation	13.9		12.1
Cost Recovery Riders (b)	29.2		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.6		3.7
Total Non-Current Regulatory Assets	337.5		340.3

Total Regulatory Assets		$355.8		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.7		$19.5
Plant Removal Obligations	19.3		18.1
Wholesale and Retail Contra AFUDC	16.7		15.5
Conservation Improvement Program	2.7		—
Other	6.7		7.0
Total Non-Current Regulatory Liabilities		$63.1		$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 Bison.

Investment in ATC (Tables)

6 Months Ended

Jun. 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	1.6
Equity in ATC Earnings	10.2
Distributed ATC Earnings	(7.9		)
Equity Investment Balance as of June 30, 2013		$111.2

ATC Summarized Financial Data [Table Text Block]

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



	Quarter Ended			Six Months Ended
ATC Summarized Financial Data	June 30,			June 30,
Income Statement Data	2013		2012	2013		2012
Millions
Revenue		$152.1	$152.2		$303.9		$299.8
Operating Expense	69.9		71.8	139.7		141.3
Other Expense	20.9		21.1	42.4		41.1
Net Income		$61.3	$59.3		$121.8		$117.4
ALLETE’s Equity in Net Income		$5.0	$4.8		$10.2		$9.4

Income Tax Expense (Tables)

6 Months Ended

Jun. 30, 2013

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Millions
Current Tax Expense (Benefit)
Federal (a)	$(0.2)			—			—			—
State (a)	—			—			—			—
Total Current Tax Expense (Benefit)	(0.2		)	—			—			—
Deferred Tax Expense (Benefit)
Federal	3.6				$4.8			$8.2			$13.2
State (b)	0.9			0.2			3.8			0.3
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Total Deferred Tax Expense	4.3			4.8			11.6			13.1
Total Income Tax Expense		$4.1			$4.8			$11.6			$13.1


(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 six months ended June 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 six months ended June 30, 2012, reflected increased state tax benefit from state renewable tax credits compared to the quarter and six months ended June 30, 2013.

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

6 Months Ended

Jun. 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 by Component



	Unrealized Gains and Losses on Available-for-sale Securities (a)		Defined Benefit Pension, Other Postretirement Items (a)		Gains and Losses on Cash Flow Hedge (a)	Total (a)
Millions
For the Quarter Ended June 30, 2013
Beginning Balance	$(0.1)		$(21.2)		$(0.3)	$(21.6)
Other Comprehensive Income (Loss) Before Reclassifications	0.1		(2.6	)	—	(2.5	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		3.1		—	3.1
Net Other Comprehensive Income	0.1		0.5		—	0.6
Ending Balance	—		$(20.7)		$(0.3)	$(21.0)

For the Six Months Ended June 30, 2013
Beginning Balance	$(0.1)		$(21.5)		$(0.4)	$(22.0)
Other Comprehensive Income (Loss) Before Reclassifications	0.6		(5.5	)	0.1	(4.8	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.5	)	6.3		—	5.8
Net Other Comprehensive Income	0.1		0.8		0.1	1.0
Ending Balance	—		$(20.7)		$(0.3)	$(21.0)


(a)	Amounts shown are net of tax.

Reclassifications Out of Accumulated Other Comprehensive Loss [Table Text Block]

Reclassifications Out of Accumulated Other Comprehensive Loss



Details About Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss (a)			Affected Income Statement Line Item
Millions
For the Quarter Ended June 30, 2013
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs		$0.7		(b)
Actuarial Gains and Losses	(5.8		)	(b)
	(5.1		)
	2.0			Income Tax Expense
	$(3.1)
Total Reclassifications	$(3.1)

For the Six Months Ended June 30, 2013
Unrealized Gains on Available-for-sale Securities		$0.8		Other Income (Expense) - Other
	(0.3		)	Income Tax Expense
		$0.5

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs		$1.2		(b)
Actuarial Gains and Losses	(11.5		)	(b)
	(10.3		)
	4.0			Income Tax Expense
	$(6.3)
Total Reclassifications	$(5.8)


(a)	Amounts in parentheses indicate charges to net income.


(b)	These components of accumulated other comprehensive loss are included in the computation of net pension and other postretirement benefit expense. (See Note 13. Pension and Other Postretirement Benefit Plans.)

Earnings Per Share and Common Stock (Tables)

6 Months Ended

Jun. 30, 2013

Earnings Per Share and Common Stock [Abstract]

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



			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 June 30,
Net Income		$14.0			$14.0		$14.4			$14.4
Average Common Shares	39.4		0.2	39.6		37.3		0.1	37.4
Earnings Per Share		$0.36			$0.35		$0.39			$0.39
For the Six Months Ended June 30,
Net Income		$46.5			$46.5		$38.8			$38.8
Average Common Shares	39.2		0.1	39.3		37.0		0.1	37.1
Earnings Per Share		$1.19			$1.18		$1.05			$1.05

Pension and Other Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 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 June 30,
Service Cost		$2.5			$2.3			$1.0			$1.1
Interest Cost	6.5			6.6			1.7			2.3
Expected Return on Plan Assets	(8.8		)	(8.9		)	(2.4		)	(2.5		)
Amortization of Prior Service Costs	—			0.1			(0.7		)	(0.5		)
Amortization of Net Loss	5.4			4.4			0.4			1.9
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$5.6			$4.5		—				$2.4

For the Six Months Ended June 30,
Service Cost		$5.0			$4.6			$2.0			$2.1
Interest Cost	13.0			13.2			3.4			4.7
Expected Return on Plan Assets	(17.6		)	(17.7		)	(4.9		)	(5.0		)
Amortization of Prior Service Costs	0.1			0.2			(1.3		)	(0.9		)
Amortization of Net Loss	10.7			8.7			0.8			3.8
Amortization of Transition Obligation	—			—			—			0.1
Net Periodic Benefit Expense		$11.2			$9.0		—				$4.8

Operations and Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Inventories [Abstract]
Fuel	$ 25.3		$ 25.3		$ 28.0
Materials and Supplies	45.7		45.7		41.8
Total Inventories	71.0		71.0		69.8
Prepayments and Other Current Assets [Abstract]
Deferred Fuel Adjustment Clause	18.3		18.3		22.5
Other	7.9		7.9		11.1
Total Prepayments and Other Current Assets	26.2		26.2		33.6
Other Current Liabilites [Abstract]
Customer Deposits	29.1		29.1		28.8
Other	31.7		31.7		33.8
Total Other Current Liabilities	60.8		60.8		62.6
Other Non-Current Liabilities [Abstract]
Asset Retirement Obligation	81.6		81.6		77.9
Other	47.7		47.7		45.4
Total Other Non-Current Liabilities	129.3		129.3		123.3
Supplemental Statement of Cash Flows Information [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized			22.8	21.7
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			28.2	14.8
Capitalized Asset Retirement Costs			1.9	2.4
AFUDC - Equity	$ 1.0	$ 1.2	$ 2.1	$ 1.9

Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Business Segments [Line Items]
Operating Revenue	$ 235.6	$ 216.4	$ 499.4	$ 456.4
Fuel and Purchased Power Expense	78.7	72.1	165.2	149.2
Operating and Maintenance Expense	103.8	96.2	208.5	196.1
Depreciation Expense	28.7	24.8	56.9	49.4
Operating Income (Loss)	24.4	23.3	68.8	61.7
Interest Expense	(12.8)	(10.1)	(25.1)	(21.1)
Equity Earnings in ATC	5.0	4.8	10.2	9.4
Other Income (Expense)	1.5	1.2	4.2	1.9
Income (Loss) Before Income Taxes	18.1	19.2	58.1	51.9
Income Tax Expense (Benefit)	4.1	4.8	11.6	13.1
Net Income	14.0	14.4	46.5	38.8
Total Assets	3,350.9	2,962.2	3,350.9	2,962.2	3,253.4
Property, Plant and Equipment - Net	2,397.2	2,177.5	2,397.2	2,177.5	2,347.6
Accumulated Depreciation	1,202.8	1,124.5	1,202.8	1,124.5
Capital Additions			100.2	235.1
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue	215.8	197.0	457.2	415.6
Fuel and Purchased Power Expense	78.7	72.1	165.2	149.2
Operating and Maintenance Expense	82.8	76.1	165.0	154.2
Depreciation Expense	27.1	23.4	53.9	46.6
Operating Income (Loss)	27.2	25.4	73.1	65.6
Interest Expense	(10.4)	(9.9)	(21.1)	(19.5)
Equity Earnings in ATC	5.0	4.8	10.2	9.4
Other Income (Expense)	1.1	1.2	2.2	2.0
Income (Loss) Before Income Taxes	22.9	21.5	64.4	57.5
Income Tax Expense (Benefit)	6.6	7.1	16.0	18.7
Net Income	16.3	14.4	48.4	38.8
Total Assets	2,997.0	2,755.4	2,997.0	2,755.4
Property, Plant and Equipment - Net	2,329.6	2,119.9	2,329.6	2,119.9
Accumulated Depreciation	1,143.2	1,070.1	1,143.2	1,070.1
Capital Additions			97.2	232.3
Investments and Other [Member]
Business Segments [Line Items]
Land in Minnesota (in acres)	6,000		6,000
Operating Revenue	19.8	19.4	42.2	40.8
Fuel and Purchased Power Expense	0	0	0	0
Operating and Maintenance Expense	21.0	20.1	43.5	41.9
Depreciation Expense	1.6	1.4	3.0	2.8
Operating Income (Loss)	(2.8)	(2.1)	(4.3)	(3.9)
Interest Expense	(2.4)	(0.2)	(4.0)	(1.6)
Equity Earnings in ATC	0	0	0	0
Other Income (Expense)	0.4	0	2.0	(0.1)
Income (Loss) Before Income Taxes	(4.8)	(2.3)	(6.3)	(5.6)
Income Tax Expense (Benefit)	(2.5)	(2.3)	(4.4)	(5.6)
Net Income	(2.3)	0	(1.9)	0
Total Assets	353.9	206.8	353.9	206.8
Property, Plant and Equipment - Net	67.6	57.6	67.6	57.6
Accumulated Depreciation	59.6	54.4	59.6	54.4
Capital Additions			$ 3.0	$ 2.8

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

6 Months Ended

12 Months Ended

Jun. 30, 2013

Dec. 31, 2012

Investments [Abstract]

ALLETE Properties

$ 91.1

Available-for-sale Securities

20.4

^[1]

26.8

^[1]

Cash Equivalents

24.4

20.7

Other

4.3

4.9

Total Other Investments

140.2

143.5

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

1.2

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

5.1

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

1.3

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

0.9

ALLETE Properties [Rollforward]

Land Inventory Beginning Balance

86.5

86.0

Deeds to Collateralized Property

0.5

Cost of Sales

(0.2)

Capitalized Improvements and Other

0.1

0.2

Land Inventory Ending Balance

86.6

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

91.1

Impairment of Real Estate

Long-Term Finance Receivables, Allowance

$ 0.6

[1]	As of June 30, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $1.2 million, in one year to less than three years was $5.1 million, in three years to less than five years was $1.3 million, and in five or more years was $0.9 million.

Derivatives - Hedged Item (Details) (Term Loan [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Term Loan [Member]
Debt Instrument [Line Items]
Term Loan Principal Amount	$ 75.0
Term Loan Variable Rate Basis	one-month LIBOR
Term Loan Basis Spread on Variable Rate	1.00%
Percentage of Debt Hedged by Interest Rate Derivatives	7.00%

Derivatives - Derivative (Details) (Interest Rate Swap [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Interest Rate Swap [Member]
Derivative [Line Items]
Interest Rate Swap Variable Rate Basis	one-month LIBOR
Interest Rate Swap Fixed Interest Rate	0.825%
Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in the value of the Swap are deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the quarter and six months ended June 30, 2013.
Interest Rate Swap Liability	$ 0.5	$ 0.7

Fair Value - Recurring Fair Value Measures (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Investments [Abstract]
Cash Equivalents	$ 24.4		$ 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	11.9		18.0
Available-for-sale - Corporate Debt Securities	8.5		8.8
Cash Equivalents	24.4		20.7
Total Fair Value of Assets	44.8		47.5
Liabilities [Abstract]
Deferred Compensation	15.7		14.0
Derivatives - Interest Rate Swap	0.5		0.7
Total Fair Value of Liabilities	16.2		14.7
Total Net Fair Value of Assets (Liabilities)	28.6		32.8
Recurring Fair Value Measurements [Member] \| Level 1 [Member]
Investments [Abstract]
Available-for-sale - Equity Securities	11.9		18.0
Available-for-sale - Corporate Debt Securities	0		0
Cash Equivalents	24.4		20.7
Total Fair Value of Assets	36.3		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)	36.3		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	8.5		8.8
Cash Equivalents	0		0
Total Fair Value of Assets	8.5		8.8
Liabilities [Abstract]
Deferred Compensation	15.7		14.0
Derivatives - Interest Rate Swap	0.5		0.7
Total Fair Value of Liabilities	16.2		14.7
Total Net Fair Value of Assets (Liabilities)	(7.7)		(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	Jun. 30, 2013	Dec. 31, 2012
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,102.6	$ 1,018.1
Long-term Debt, Including Current Portion - Fair Value	$ 1,160.2	$ 1,143.7

Regulatory Matters - Electric Rates (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013 Bison Wind Energy Center [Member] MW	Jun. 01, 2011 MPUC 2010 Minnesota Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Jun. 30, 2013 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Years Customers	Jun. 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

Regulatory Matters - The Patient Protection and Affordable Care Act of 2010 (PPACA) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended			3 Months Ended	12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 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	4.3	4.8	11.6	13.1		(2.9)
Non-Current Regulatory Assets	$ 337.5		$ 337.5		$ 340.3	$ 5.0

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

Jun. 30, 2013

Dec. 31, 2012

Current Regulatory Assets

$ 18.3

$ 22.5

337.5

340.3

Total Regulatory Assets

355.8

362.8

63.1

60.1

Income Taxes [Member]

17.7

19.5

Plant Removal Obligations [Member]

19.3

18.1

Wholesale and Retail Contra AFUDC [Member]

16.7

15.5

Conservation Improvement Program [Member]

2.7

Other [Member]

6.7

7.0

Deferred Fuel [Member]

Current Regulatory Assets

18.3

^[1]

22.5

^[1]

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

251.5

260.7

Income Taxes [Member]

34.3

36.0

Asset Retirement Obligation [Member]

13.9

12.1

Cost Recovery Riders [Member]

29.2

^[2]

18.5

^[2]

PPACA Income Tax Deferral [Member]

5.0

Conservation Improvement Program [Member]

4.3

Other [Member]

Current Tax Expense (Benefit) [Abstract]

$ 3.6

$ 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 Bison.

Investment in ATC (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 31, 2013	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Investment in ATC [Abstract]
Ownership Percentage		8.00%		8.00%
Approved Return on Common Equity		12.20%		12.20%
Expected Additional Investment		$ 0.7		$ 0.7
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2012	111.2			107.3
Cash Investments	0.8			1.6
Equity Earnings in ATC		5.0	4.8	10.2	9.4
Distributed ATC Earnings				(7.9)
Equity Investment Balance as of June 30, 2013		111.2		111.2
ATC Summarized Financial Data [Abstract]
Revenue		152.1	152.2	303.9	299.8
Operating Expense		69.9	71.8	139.7	141.3
Other Expense		20.9	21.1	42.4	41.1
Net Income		61.3	59.3	121.8	117.4
ALLETE's Equity in Net Income		$ 5.0	$ 4.8	$ 10.2	$ 9.4

Short-Term and Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended
	Apr. 02, 2013	Jun. 30, 2013	Dec. 31, 2012
Financial Covenants [Abstract]
Required Indebtedness to Total Capital Ratio		0.65
Actual Indebtedness to Total Capital Ratio		0.47
Debt Instrument [Line Items]
Short-Term Debt Outstanding		$ 37.9	$ 84.5
Long-Term Debt Outstanding		1,064.7	933.6
Proceeds from Issuance of First Mortgage Bonds	150.0
ALLETE Bonds 4.86% Series Due 2013 [Member]
Debt Instrument [Line Items]
Short-Term Debt Outstanding			60.0
ALLETE Bonds 1.83% Due April 2018 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bonds	50.0
First Mortgage Bonds, Interest Rate	1.83%
ALLETE Bonds 3.30% Due October 2028 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bonds	40.0
First Mortgage Bonds, Interest Rate	3.30%
ALLETE Bonds 4.21% Due October 2043 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bonds	$ 60.0
First Mortgage Bonds, Interest Rate	4.21%

Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 1.0	$ 1.2	$ 2.1	$ 1.9
Gain on Sale of Available-for-sale Securities	0	0	(0.8)	0
Investments and Other Income	0.5	0	1.3	0
Total Other Income	$ 1.5	$ 1.2	$ 4.2	$ 1.9

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

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Dec. 31, 2012

Federal

$ (0.2)

^[1]

$ 0

^[1]

$ 0

^[1]

$ 0

^[1]

State

^[1]

Total Current Tax Expense (Benefit)

(0.2)

Deferred Tax Expense (Benefit) [Abstract]

Federal

3.6

4.8

8.2

13.2

State

0.9

^[2]

0.2

^[2]

3.8

^[2]

0.3

^[2]

Investment Tax Credit Amortization

(0.2)

(0.4)

Total Deferred Tax Expense

4.3

4.8

11.6

13.1

Total Income Tax Expense

4.1

4.8

11.6

13.1

Effective Income Tax Rate

20.00%

25.20%

Federal Statutory Income Tax Rate

41.00%

Uncertain Tax Positions [Abstract]

Gross Unrecognized Tax Benefits

2.6

2.7

Unrecognized Tax Benefits that Would Favorably Impact Effective Tax Rate

$ 0.7

[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 six months ended June 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 six months ended June 30, 2012, reflected increased state tax benefit from state renewable tax credits compared to the quarter and six months ended June 30, 2013.

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

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Mar. 31, 2013

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss) [Line Items]

Other Comprehensive Income (Loss) Before Reclassifications

$ (21.0)

^[1]

$ (21.0)

^[1]

$ (21.6)

^[1]

$ (22.0)

^[1]

(2.5)

^[1]

(4.8)

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Loss

(3.1)

^[1],[2]

(5.8)

^[1],[2]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

0.6

^[1]

(0.1)

1.0

^[1]

1.3

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

(5.1)

^[2]

(10.3)

^[2]

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

0.7

^[3]

1.2

^[3]

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

(5.8)

^[2],[3]

(11.5)

^[2],[3]

Other Income (Expense) - Other [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

0.8

Income Tax Expense [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(0.3)

^[2]

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

2.0

4.0

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

Accumulated Other Comprehensive Income (Loss) [Line Items]

Other Comprehensive Income (Loss) Before Reclassifications

^[1]

(0.1)

^[1]

(0.1)

^[1]

0.1

^[1]

0.6

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Loss

^[1]

0.5

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

0.1

^[1]

0.1

^[1]

Defined Benefit Pension, Other Postretirement Items [Member]

Other Comprehensive Income (Loss) Before Reclassifications

(20.7)

^[1]

(20.7)

^[1]

(21.2)

^[1]

(21.5)

^[1]

(2.6)

^[1]

(5.5)

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Loss

(3.1)

^[1],[2]

(6.3)

^[1],[2]

Accumulated Other Comprehensive Income (Loss) [Line Items]

0.5

^[1]

0.8

^[1]

Gains and Losses on Cash Flow Hedge [Member]

Other Comprehensive Income (Loss) Before Reclassifications

(0.3)

^[1]

(0.3)

^[1]

(0.3)

^[1]

(0.4)

^[1]

^[1]

0.1

^[1]

Amounts Reclassified From Accumulated Other Comprehensive Loss

^[1]