Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Sep. 30, 2010	Dec. 31, 2009
Current Assets
Cash and Cash Equivalents	$ 92.3	$ 25.7
Accounts Receivable (Less Allowance of $0.9 at September 30, 2010 and December 31, 2009)	112.1	118.5
Inventories	62.9	57.0
Prepayments and Other	26.7	24.3
Total Current Assets	294.0	225.5
Property, Plant and Equipment - Net	1,742.6	1,622.7
Regulatory Assets	282.5	293.2
Investment in ATC	92.0	88.4
Other Investments	134.4	130.5
Other Non-Current Assets	33.6	32.8
Total Assets	2,579.1	2,393.1
Current Liabilities
Accounts Payable	66.5	62.1
Accrued Taxes	18.0	20.6
Accrued Interest	12.3	11.1
Long-Term Debt Due Within One Year	1.6	5.2
Notes Payable	1.0	1.9
Other	31.6	32.2
Total Current Liabilities	131.0	133.1
Long-Term Debt	784.2	695.8
Deferred Income Taxes	321.0	253.1
Regulatory Liabilities	46.0	47.1
Other Non-Current Liabilities	312.8	325.0
Total Liabilities	1,595.0	1,454.1
ALLETE's Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 35.8 and 35.2 Shares Outstanding	634.1	613.4
Unearned ESOP Shares	(38.2)	(45.3)
Accumulated Other Comprehensive Loss	(23.2)	(24.0)
Retained Earnings	402.2	385.4
Total ALLETE Equity	974.9	929.5
Non-Controlling Interest in Subsidiaries	9.2	9.5
Total Equity	984.1	939.0
Total Liabilities and Equity	$ 2,579.1	$ 2,393.1

Parenthetical Data to The Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Sep. 30, 2010	Dec. 31, 2009
Current Assets
Accounts Receivable, Allowance	$ 0.9	$ 0.9
ALLETE's Equity
Common Stock Par Value	$ 0	$ 0
Common Stock Shares Authorized	80.0	80.0
Common Stock Shares Outstanding	35.8	35.2

Consilidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Operating Revenue
Operating Revenue	$ 224.1	$ 178.8	$ 668.9	$ 550.7
Prior Year Rate Refunds	0	0	0	(7.6)
Total Operating Revenue	224.1	178.8	668.9	543.1
Operating Expenses
Fuel and Purchased Power	79.0	69.8	233.1	199.4
Operating and Maintenance	89.8	67.5	262.9	224.7
Depreciation	20.0	16.1	59.8	46.8
Total Operating Expenses	188.8	153.4	555.8	470.9
Operating Income	35.3	25.4	113.1	72.2
Other Income (Expense)
Interest Expense	(9.7)	(8.3)	(28.1)	(25.4)
Equity Earnings in ATC	4.5	4.4	13.4	12.9
Other	0.6	0.8	3.8	3.8
Total Other Expense	(4.6)	(3.1)	(10.9)	(8.7)
Income Before Non-Controlling Interest and Income Taxes	30.7	22.3	102.2	63.5
Income Tax Expense	11.2	6.5	40.5	21.5
Net Income	19.5	15.8	61.7	42.0
Less: Non-Controlling Interest in Subsidiaries	(0.1)	(0.2)	(0.3)	(0.3)
Net Income Attributable to ALLETE	$ 19.6	$ 16.0	$ 62.0	$ 42.3
Average Shares of Common Stock
Basic	34.4	32.8	34.1	31.8
Diluted	34.5	32.9	34.2	31.9
Basic Earnings Per Share of Common Stock	$ 0.57	$ 0.49	$ 1.82	$ 1.33
Diluted Earnings Per Share of Common Stock	$ 0.56	$ 0.49	$ 1.81	$ 1.33
Dividends Per Share of Common Stock	$ 0.44	$ 0.44	$ 1.32	$ 1.32

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
Operating Activities
Net Income	$ 61.7	$ 42.0
Allowance for Funds Used During Construction	(3.4)	(4.5)
Income from Equity Investments, Net of Dividends	(2.2)	(0.2)
Gain on Real Estate Foreclosure	(0.7)	0
Gain on Sale of Assets	0	(0.1)
Depreciation Expense	59.8	46.8
Amortization of Debt Issuance Costs	0.7	0.7
Deferred Income Tax Expense	65.0	38.9
Stock Compensation Expense	1.6	1.6
Bad Debt Expense	0.8	1.2
Changes in Operating Assets and Liabilities
Accounts Receivable	5.6	(4.1)
Inventories	(5.8)	(4.7)
Prepayments and Other	(2.4)	(0.3)
Accounts Payable	3.7	(4.4)
Other Current Liabilities	(2.0)	11.4
Changes in Regulatory and Other Non-Current Assets	10.6	(7.0)
Changes in Regulatory and Other Non-Current Liabilities	(5.0)	(11.0)
Cash from Operating Activities	188.0	106.3
Investing Activities
Proceeds from Sale of Available-for-Sale Securities	0.6	1.0
Payments for Purchase of Available-for-Sale Securities	(1.8)	(1.8)
Investment in ATC	(1.2)	(5.4)
Changes to Other Investments	(2.6)	(0.5)
Additions to Property, Plant and Equipment	(172.7)	(200.1)
Proceeds from Sale of Assets	0	0.3
Cash for Investing Activities	(177.7)	(206.5)
Financing Activities
Proceeds from Issuance of Common Stock	19.0	53.7
Proceeds from Issuance of Long-Term Debt	155.0	44.7
Reductions of Long-Term Debt	(70.2)	(3.0)
Debt Issuance Costs	(1.4)	(0.5)
Dividends on Common Stock	(45.2)	(41.7)
Changes in Notes Payable	(0.9)	(0.7)
Cash from Financing Activities	56.3	52.5
Change in Cash and Cash Equivalents	66.6	(47.7)
Cash and Cash Equivalents at Beginning of Period	25.7	102.0
Cash and Cash Equivalents at End of Period	92.3	54.3
Profit Loss	$ 61.7	$ 42.0

Operations and Significant Accounting Policies

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Operations and Significant Accounting Policies

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

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

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

	September 30,	December 31,
Inventories	2010	2009
Millions
Fuel	$24.5	$23.0
Materials and Supplies	38.4	34.0
Total Inventories	$62.9	$57.0

	September 30,	December 31,
Prepayments and Other Current Assets	2010	2009
Millions
Deferred Fuel Adjustment Clause	$19.5	$15.5
Other	7.2	8.8
Total Prepayments and Other Current Assets	$26.7	$24.3

	September 30,	December 31,
Other Non-Current Liabilities	2010	2009
Millions
Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Benefit Plans	$220.2	$231.2
Asset Retirement Obligation	49.4	44.6
Other	43.2	49.2
Total Other Non-Current Liabilities	$312.8	$325.0

Supplemental Statement of Cash Flows Information.

For the Nine Months Ended September 30,	2010	2009
Millions
Cash Paid (Received) During the Period for
Interest – Net of Amounts Capitalized	$26.1	$23.7
Income Taxes (Net of refunds received of $32.1 and $5.3) (a)	$(29.4)	$(4.2)

Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$0.7	$(16.5)
AFUDC – Equity	$3.4	$4.5
ALLETE Common Stock contributed to the Defined Benefit Pension Plan	–	$(12.0)

(a)

Due to bonus depreciation provisions in the Small Business Jobs Act of 2010 and the American Recovery and Reinvestment Act of 2009, lower estimated tax payments were made in 2010 and 2009. Refunds received in 2010 resulted from a 2009 net operating loss which was utilized by carrying it back against prior years’ taxable income and the completion of a state income tax audit.

Recently Issued Accounting Standards.

Receivables. In July 2010, the FASB issued an accounting standards update requiring expanded disclosures on allowances for credit losses and the credit quality of the financing receivables of an entity. This guidance also requires a roll forward schedule of the allowance for credit losses for each reporting period. The guidance for greater transparency is effective for annual reporting periods ending after December 15, 2010, and the roll forward requirement is effective January 1, 2011. As the amended guidance provides only disclosure requirements, the adoption of this standard will not have an impact on our consolidated financial position, results of operations or cash flows.

Recently Adopted Accounting Standards.

Derivative Instruments and Hedging Activities. In March 2010, the FASB issued new guidance on the accounting for credit derivatives that are embedded in beneficial interests in securitized financial assets. This new guidance eliminated the scope exception for embedded credit derivatives and provided new guidance on the evaluation to be performed. This guidance was effective June 15, 2010. As of September 30, 2010, we did not have any embedded credit derivatives.

Subsequent Events. In February 2010, the FASB issued an accounting standards update that eliminates the requirement to disclose the date through which subsequent events have been evaluated. The amended guidance was adopted and effective during the first quarter of 2010, and did not have an impact on our consolidated financial position, results of operations or cash flows.

Fair Value. In January 2010, the FASB issued an amendment to the fair value measurement and disclosure standard improving disclosures about fair value measurements. This amended guidance requires separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The amended guidance also requires that in the Level 3 reconciliation, the information about purchases, sales, issuances, and settlements be disclosed separately on a gross basis rather than as one net number. The guidance for the Level 1 and 2 disclosures was adopted January 1, 2010, and did not have an impact on our consolidated financial position, results of operations or cash flows. The guidance for the activity in Level 3 disclosures is effective January 1, 2011, and is not expected to have an impact on our consolidated financial position, results of operations or cash flows as the amended guidance provides only disclosure requirements.

Variable Interest Entities (VIEs). In June 2009, the FASB issued authoritative guidance changing the approach to determine a VIE’s primary beneficiary and requiring ongoing assessments of whether an enterprise is the primary beneficiary of a VIE. This guidance also requires additional disclosures about a company’s involvement with VIEs and any significant changes in risk exposure due to that involvement. This guidance was adopted January 1, 2010, and did not have an impact on our consolidated financial position, results of operations or cash flows.

Business Segments

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Business Segments

NOTE 2. BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment. This segment also includes a small amount of non-rate base generation, approximately 7,000 acres of land held-for-sale in Minnesota, and earnings on cash and investments.

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Quarter Ended September 30, 2010
Operating Revenue	$224.1	$204.8	$19.3
Fuel and Purchased Power	79.0	79.0	–
Operating and Maintenance	89.8	70.2	19.6
Depreciation Expense	20.0	18.9	1.1
Operating Income (Loss)	35.3	36.7	(1.4)
Interest Expense	(9.7)	(8.0)	(1.7)
Equity Earnings in ATC	4.5	4.5	–
Other Income (Expense)	0.6	1.3	(0.7)
Income (Loss) Before Non-Controlling Interest and Income Taxes	30.7	34.5	(3.8)
Income Tax Expense (Benefit)	11.2	12.4	(1.2)
Net Income (Loss)	19.5	22.1	(2.6)
Less: Non-Controlling Interest in Subsidiaries	(0.1)	–	(0.1)
Net Income (Loss) Attributable to ALLETE	$19.6	$22.1	$(2.5)

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Quarter Ended September 30, 2009
Operating Revenue	$178.8	$160.1	$18.7
Fuel and Purchased Power	69.8	69.8	–
Operating and Maintenance	67.5	50.1	17.4
Depreciation Expense	16.1	15.0	1.1
Operating Income	25.4	25.2	0.2
Interest Expense	(8.3)	(7.0)	(1.3)
Equity Earnings in ATC	4.4	4.4	–
Other Income (Expense)	0.8	1.6	(0.8)
Income (Loss) Before Non-Controlling Interest and Income Taxes	22.3	24.2	(1.9)
Income Tax Expense (Benefit)	6.5	7.6	(1.1)
Net Income (Loss)	15.8	16.6	(0.8)
Less: Non-Controlling Interest in Subsidiaries	(0.2)	–	(0.2)
Net Income (Loss) Attributable to ALLETE	$16.0	$16.6	$(0.6)

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Nine Months Ended September 30, 2010
Operating Revenue	$668.9	$615.0	$53.9
Fuel and Purchased Power	233.1	233.1	–
Operating and Maintenance	262.9	209.3	53.6
Depreciation Expense	59.8	56.6	3.2
Operating Income (Loss)	113.1	116.0	(2.9)
Interest Expense	(28.1)	(23.3)	(4.8)
Equity Earnings in ATC	13.4	13.4	–
Other Income	3.8	3.6	0.2
Income (Loss) Before Non-Controlling Interest and Income Taxes	102.2	109.7	(7.5)
Income Tax Expense (Benefit)	40.5	44.5	(4.0)
Net Income (Loss)	61.7	65.2	(3.5)
Less: Non-Controlling Interest in Subsidiaries	(0.3)	–	(0.3)
Net Income (Loss) Attributable to ALLETE	$62.0	$65.2	$(3.2)

As of September 30, 2010
Total Assets	$2,579.1	$2,299.7	$279.4
Property, Plant and Equipment – Net	$1,742.6	$1,698.1	$44.5
Accumulated Depreciation	$1,022.2	$973.2	$49.0
Capital Additions	$175.5	$174.3	$1.2

		Regulated	Investments
	Consolidated	Operations	and Other
Millions
For the Nine Months Ended September 30, 2009
Operating Revenue	$550.7	$493.9	$56.8
Prior Year Rate Refunds	(7.6)	(7.6)	–
Total Operating Revenue	543.1	486.3	56.8
Fuel and Purchased Power	199.4	199.4	–
Operating and Maintenance	224.7	169.8	54.9
Depreciation Expense	46.8	43.4	3.4
Operating Income (Loss)	72.2	73.7	(1.5)
Interest Expense	(25.4)	(20.9)	(4.5)
Equity Earnings in ATC	12.9	12.9	–
Other Income (Expense)	3.8	4.5	(0.7)
Income (Loss) Before Non-Controlling Interest and Income Taxes	63.5	70.2	(6.7)
Income Tax Expense (Benefit)	21.5	25.2	(3.7)
Net Income (Loss)	42.0	45.0	(3.0)
Less: Non-Controlling Interest in Subsidiaries	(0.3)	–	(0.3)
Net Income (Loss) Attributable to ALLETE	$42.3	$45.0	$(2.7)

As of September 30, 2009
Total Assets	$2,255.1	$2,005.3	$249.8
Property, Plant and Equipment – Net	$1,530.5	$1,478.9	$51.6
Accumulated Depreciation	$937.0	$885.4	$51.6
Capital Additions	$186.7	$185.0	$1.7

Investments

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Investments

NOTE 3. INVESTMENTS

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

	September 30,	December 31,
Other Investments	2010	2009
Millions
ALLETE Properties	$94.5	$93.1
Available-for-sale Securities	30.0	29.5
Other	9.9	7.9
Total Other Investments	$134.4	$130.5

	September 30,	December 31,
ALLETE Properties	2010	2009
Millions
Land Held-for-sale Beginning Balance	$74.9	$71.2
Additions during period:
Collateralized Property Reacquired (a)	9.9	–
Capitalized Improvements and Other	0.8	5.6
Deductions during period: Cost of Real Estate Sold	–	(1.9)
Land Held-for-sale Ending Balance	85.6	74.9
Long-Term Finance Receivables	4.5	12.9
Other	4.4	5.3
Total Real Estate Assets	$94.5	$93.1

(a)	Collateralized property reacquired resulted primarily from a purchaser which filed for voluntary Chapter 11 bankruptcy and is recorded net of estimated selling costs.

Land Held-for-sale. Land held-for-sale is recorded at the lower of cost or fair value determined by the evaluation of individual land parcels. Land values are reviewed for impairment and no impairments were recorded for the nine months ended September 30, 2010 (none in 2009).

Long-Term Finance Receivables. Long-term finance receivables, which are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. There was no allowance for doubtful accounts as of September 30, 2010 ($0.4 million as of December 31, 2009). The receivables have maturities up to three years and no impairment was recorded during the nine months ended September 30, 2010 ($0.1 million during the nine months ended September 30, 2009).

In June 2010, ALLETE Properties received deeds in lieu of foreclosure to properties which had been sold in multiple transactions over various years to one purchaser. The properties were sold with seller financing, of which $7.0 million remained due and owing from the purchaser that filed for voluntary Chapter 11 bankruptcy protection in June 2009. The bankruptcy trustee approved the transfer of the properties back to ALLETE Properties in satisfaction of the amount owed. The fair value of the properties received net of selling expenses was $8.8 million. The receipt of properties resulted in a pretax gain of $0.7 million after reflecting other liabilities assumed and non-controlling interest.

Auction Rate Securities. Included in Available-for-sale Securities as of September 30, 2010, is an auction rate municipal bond of $6.7 million ($6.7 million at December 31, 2009) with a stated maturity date of March 1, 2024. Our ARS consist of guaranteed student loans insured or reinsured by the federal government. ARS were historically auctioned every 35 days to set new rates and provided a liquidating event in which investors could either buy or sell securities. Since 2008, the auctions for ARS have been unable to sustain themselves due to the overall lack of market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified our ARS as long-term investments and have the ability to hold these securities to maturity, until called by the issuer, or until liquidity returns to this market. We anticipate our ARS will be redeemed at par within the next year; however, the investment remains classified as long-term.

- Definition

This item represents the entire disclosure related to Investments in Certain Debt and Equity Securities (and certain other trading assets) which include all debt and equity securities (other than those equity securities accounted for under the equity or cost methods of accounting) with readily determinable fair values. Other trading assets include assets that are carried on the balance sheet at fair value and held for trading purposes. A debt security represents a creditor relationship with an enterprise that is in the form of a security. Debt securities include, among other items, US Treasury securities, US government securities, municipal securities, corporate bonds, convertible debt, commercial paper, and all securitized debt instruments. An equity security represents an ownership interest in an enterprise or the right to acquire or dispose of an ownership interest in an enterprise at fixed or determinable prices. Equity securities include, among other things, common stock, certain preferred stock, warrant rights, call options, and put options, but do not include convertible debt. An entity may opt to provide the reader with additional narrative text to better understand the nature of investments in debt and equity securities (and other trading assets).

+ References+ Details

Fair Value

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Fair Value

NOTE 4. 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 included in our 2009 Form 10-K.

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010, and December 31, 2009. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of September 30, 2010
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities – Mutual Funds	$17.5	–	–	$17.5
Available-for-sale Securities
Corporate Debt Securities	–	$7.4	–	7.4
Debt Securities Issued by States of the United States (ARS)	–	–	$6.7	6.7
Total Available-for-sale Securities	–	7.4	6.7	14.1
Money Market Funds	2.8	–	–	2.8
Total Fair Value of Assets	$20.3	$7.4	$6.7	$34.4

Liabilities:
Deferred Compensation	–	$13.1	–	$13.1
Total Fair Value of Liabilities	–	$13.1	–	$13.1

Total Net Fair Value of Assets (Liabilities)	$20.3	$(5.7)	$6.7	$21.3

	Fair Value as of December 31, 2009
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities – Mutual Funds	$17.8	–	–	$17.8
Available-for-sale Securities
Corporate Debt Securities	–	$6.4	–	6.4
Debt Securities Issued by States of the United States (ARS)	–	–	$6.7	6.7
Total Available-for-sale Securities	–	6.4	6.7	13.1
Derivatives - Financial Transmission Rights	–	–	0.7	0.7
Money Market Funds	1.4	–	–	1.4
Total Fair Value of Assets	$19.2	$6.4	$7.4	$33.0

Liabilities:
Deferred Compensation	–	$14.6	–	$14.6
Total Fair Value of Liabilities	–	$14.6	–	$14.6

Total Net Fair Value of Assets (Liabilities)	$19.2	$(8.2)	$7.4	$18.4

Recurring Fair Value Measures Activity in Level 3	Derivatives		Debt Securities Issued by States of the United States (ARS)
Millions
Balance as of December 31, 2009 and December 31, 2008, respectively	$0.7	–	$6.7	$15.2
Purchases, Sales, Issuances and Settlements, Net	(0.7)	$1.1	–	(0.9)
Balance as of September 30, 2010 and September 30, 2009, respectively	–	$1.1	$6.7	$14.3

The Company’s policy is to recognize transfers in or out of Levels 1, 2 or 3 as of the actual date of the event or change in circumstances that caused the transfer. For the nine months ended September 30, 2010 and 2009, there were no transfers in or out of Levels 1, 2 or 3.

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

Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
September 30, 2010	$785.8	$828.8
December 31, 2009	$701.0	$734.8

- Definition

This element represents the disclosure related to the fair value measurement of assets and liabilities which includes [financial] instruments measured at fair value that are classified in stockholders' equity. Such assets and liabilities may be measured on a recurring or nonrecurring basis. The disclosures which may be required or desired include: (1) for assets and liabilities measured on a recurring basis, disclosure may include: (a) the fair value measurements at the reporting date; (b) the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets or liabilities (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3); (c) for fair value measurements using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (i) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (ii) purchases, sales, issuances, and settlements (net); (iii) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs); (d) the amount of the total gains or losses for the period in subparagraph (c) (i) above included in earnings (or changes in net assets) that are attributable to the change in unrealized gains or losses relating to those assets and liabilities still held at the reporting date and a description of where those unrealized gains or losses are reported in the statement of income (or activities); (e) the valuation technique(s) used to measure fair value and a discussion of changes in valuation techniques, if any, during the period and (2) for assets and liabilities that are measured at fair value on a nonrecurring basis (for example, impaired assets) disclosure may include, in addition to (a) above: (a) the reasons for the fair value measurements recorded; (b) the same as (b) above; (c) for fair value measurements using significant unobservable inputs (Level 3), a description of the inputs and the information used to develop the inputs; and (d) the valuation technique(s) used to measure fair value and a discussion of changes, if any, in the valuation technique(s) used to measure similar assets and/or liabilities in prior periods.

+ References+ Details

Regulatory Matters

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Regulatory Matters

NOTE 5. REGULATORY MATTERS

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

2010 Rate Case. On November 2, 2009, Minnesota Power filed an $81 million retail rate increase request for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance, and bring new renewable energy to northeastern Minnesota. Interim rates were put into effect on January 1, 2010, and were originally estimated to increase revenues by $48.5 million in 2010. In April 2010, we adjusted our initial filing for events that had occurred since November 2009 – primarily increased sales to our industrial customers – resulting in a retail rate increase request of $72 million, a return on equity request of 11.25 percent, and a capital structure consisting of 54.29 percent equity and 45.71 percent debt. As a result of these increased sales, interim rates are estimated to be approximately $53 million during 2010.

On September 29, 2010, the MPUC addressed the retail rate increase request and approved a 10.38 percent return on common equity and a 54.29 percent equity ratio. We estimate that the MPUC will order an overall retail electric rate increase of approximately $54 million when it issues its written order on the rate request, which is expected by November 2, 2010. Once the written order has been issued, any party may request reconsideration by the MPUC. Any party who seeks reconsideration may thereafter appeal to the Minnesota Court of Appeals. We will continue collecting interim rates from our customers until the new rates go into effect, which will be after the reconsideration period has expired, any appeals are addressed, and after all compliance filings are completed and accepted. Reconsideration, or appeal, of the written order, or modifications during the compliance period, could affect the final rate increase estimate. A final order, after reconsideration, is expected no later than the first quarter of 2011. Final rates are expected to be near the amount collected under interim rates, therefore, we expect little or no interim rate refunds to be issued.

2008 Rate Case – Fuel and Purchase Power. In the final 2008 retail rate case order, the MPUC approved the stipulation and settlement agreement that affirmed Minnesota Power’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the 2008 retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to Minnesota Power’s fuel clause operation.

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. In 2008, Minnesota Power entered into new formula based rate contracts with these customers which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are set at the beginning of the year based on expected costs and provide for a true-up calculation for actual costs. Wholesale rate increases of approximately $6 million and $7 million annually were implemented on February 1, 2009, and January 1, 2010, respectively. The 2009 true-up calculation resulted in additional revenue accruals of $6.0 million at the end of 2009. The majority of these additional revenue accruals have been collected as of September 30, 2010.

Wisconsin Rates. SWL&P’s current retail rates are based on a 2008 PSCW retail rate order, effective January 1, 2009. On May 17, 2010, SWL&P filed a rate increase request with the PSCW seeking an average overall increase of 3.6 percent for retail customers (a 1.4 percent increase in electric rates, a 3.0 percent increase in natural gas rates, and a 17.9 percent increase in water rates). The rate filing seeks an overall return on equity of 11.3 percent, and a capital structure consisting of 56.9 percent equity and 43.1 percent debt. On an annualized basis, the requested rate increase would generate approximately $3 million in additional revenue. Evidentiary and public hearings were held on September 22, 2010. The Company anticipates new rates will take effect during the first quarter of 2011. We cannot predict the level of rates that may be approved by the PSCW.

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs as regulatory assets, which are probable of recovery in future utility rates. Regulatory liabilities represent amounts expected to be credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

	September 30,	December 31,
Regulatory Assets and Liabilities	2010	2009
Millions
Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Benefit Plans	$226.7	$235.8
Boswell Unit 3 Environmental Rider (a)	20.5	20.9
Deferred Fuel (b)	24.9	20.8
Income Taxes	15.5	15.7
Asset Retirement Obligation	7.4	6.3
Deferred MISO Costs	1.3	2.4
Premium on Reacquired Debt	1.9	2.0
Rate Case Expenses	1.4	1.4
Other	2.4	3.4
Total Regulatory Assets	$302.0	$308.7

Regulatory Liabilities
Income Taxes	$24.0	$25.9
Plant Removal Obligations	17.9	16.9
Other	4.1	4.3
Total Regulatory Liabilities	$46.0	$47.1

(a)

MPUC-approved current cost recovery rider related to environmental improvements that were placed in service in November 2009. As part of our 2010 rate case, on September 29, 2010, the MPUC approved a proposal to move the rider balance to plant to recover in rate base, which will be effective upon a final rate order.

(b)

As of September 30, 2010 and December 31, 2009, approximately $5 million of this balance relates to deferred fuel costs incurred under the former base cost of fuel calculation. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.

Current and Non-Current	September 30,	December 31,
Regulatory Assets and Liabilities	2010	2009
Millions
Total Current Regulatory Assets (a)	$19.5	$15.5
Total Non-Current Regulatory Assets	282.5	293.2
Total Regulatory Assets	$302.0	$308.7

Total Non-Current Regulatory Liabilities	$46.0	$47.1
Total Regulatory Liabilities	$46.0	$47.1

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

Investment in ATC

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Investment in ATC

NOTE 6. 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 provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of encouraging the independent operation and ownership of, and investment in, transmission facilities. We account for our investment in ATC under the equity method of accounting. As of September 30, 2010, our equity investment balance in ATC was $92.0 million ($88.4 million as of December 31, 2009). On October 29, 2010, we invested an additional $0.4 million in ATC for a total investment of $1.6 million in 2010.

ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2009	$88.4
Cash Investments	1.2
Equity in ATC Earnings	13.4
Distributed ATC Earnings	(11.0)
Equity Investment Balance as of September 30, 2010	$92.0

ATC's summarized financial data for the quarter and nine months ended September 30, 2010 and 2009, is as follows:

	Quarter Ended		Nine Months Ended
ATC Summarized Financial Data	September 30,		September 30,
Income Statement Data	2010	2009	2010	2009
Millions
Revenue	$136.9	$132.3	$414.1	$387.5
Operating Expense	59.8	58.7	185.1	172.3
Other Expense	22.1	19.8	64.8	57.8
Net Income	$55.0	$53.8	$164.2	$157.4

ALLETE’s Equity in Net Income	$4.5	$4.4	$13.4	$12.9

Short-term and Long-term Debt

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Short-term and Long-term Debt

NOTE 7. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. Total short-term debt outstanding as of September 30, 2010, was $2.6 million ($7.1 million at December 31, 2009) and consisted of notes payable and long-term debt due within one year.

Long-Term Debt. In February 2010, we issued $80.0 million in principal amount of unregistered First Mortgage Bonds in the private placement market in three series as follows:

Issue Date	Maturity	Principal Amount	Interest Rate
February 17, 2010	April 15, 2021	$15 Million	4.85%
February 17, 2010	April 15, 2025	$30 Million	5.10%
February 17, 2010	April 15, 2040	$35 Million	6.00%

We used the proceeds from the sale of the bonds to pay off an outstanding draw of $65 million on our syndicated revolving credit facility, to fund utility capital investments and for general corporate purposes.

In August 2010, we issued $75.0 million in principal amount of unregistered First Mortgage Bonds in the private placement market in two series as follows:

Issue Date	Maturity	Principal Amount	Interest Rate
August 17, 2010	October 15, 2025	$30 Million	4.90%
August 17, 2010	April 15, 2040	$45 Million	5.82%

We used the proceeds to fund utility capital investments and for general corporate purposes.

For the February and August 2010 bond issuances (the Bonds), we have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to the terms and conditions of our utility mortgage. The Bonds were sold in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded Debt to Total Capital (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00 measured quarterly. As of September 30, 2010, our ratio was approximately 0.43 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of September 30, 2010, ALLETE was in compliance with its financial covenants.

Other Income (Expense)

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Other Income Expense

NOTE 8. OTHER INCOME

The components of other income were as follows:

	Quarter Ended		Nine Months Ended
	September 30,		September 30,
	2010	2009	2010	2009
Millions
AFUDC – Equity	$1.4	$1.6	$3.4	$4.5
Investment and Other Income (Expense)	(0.8)	(0.8)	0.4	(0.7)
Total Other Income	$0.6	$0.8	$3.8	$3.8

Income Tax Expense

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Income Tax Expense

NOTE 9. INCOME TAX EXPENSE

On March 23, 2010, the Patient Protection and Affordable Care Act (H.R. 3590), which was subsequently amended on March 30, 2010, was signed into law by the President. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of the provisions changes 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 in the period of enactment. Consequently, the elimination of the previously recorded tax benefit resulted in a non-recurring charge to net income of $4.0 million in the first quarter of 2010. On October 8, 2010, we submitted a filing with the MPUC to request deferral of the retail impact of Medicare Part D of this legislation. We are unable to predict the outcome at this time.

	Quarter Ended		Nine Months Ended
	September 30,		September 30,
	2010	2009	2010	2009
Millions
Current Tax Expense (Benefit)
Federal (a)	$(31.7)	$(7.9)	$(24.5)	$(16.7)
State	1.0	(0.5)	–	(0.7)
Total Current Tax Expense (Benefit)	(30.7)	(8.4)	(24.5)	(17.4)
Deferred Tax Expense
Federal (b)	41.0	12.6	59.0	33.5
State	1.2	2.5	6.7	6.1
Deferred Tax Credits	(0.3)	(0.2)	(0.7)	(0.7)
Total Deferred Tax Expense	41.9	14.9	65.0	38.9
Total Income Tax Expense	$11.2	$6.5	$40.5	$21.5

(a)

The federal current tax benefit in 2010 primarily resulted from the implementation of tax planning initiatives and bonus depreciation provisions in the Small Business Jobs Act of 2010, resulting in a projected net operating loss for 2010. The 2010 projected net operating loss will be partially utilized by carrying it back against prior years’ income with the remainder carried forward to offset future years’ income. The federal current tax benefit in 2009 primarily resulted from the bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009. The 2009 net operating loss has been utilized by carrying it back against prior years’ taxable income.

(b)

Federal deferred tax expense for 2010 is higher due to tax planning initiatives and bonus depreciation provisions of the Small Business Jobs Act of 2010. Due to the bonus depreciation provisions, we expect to be in a net operating loss position for 2010. We expect to fully utilize the projected net operating loss carryforward; therefore a deferred tax asset has been recorded to recognize the resulting tax benefit. Included in the nine month period ending September 30, 2010, is a one-time charge of $4.0 million as a result of the Patient Protection and Affordable Care Act eliminating the tax deduction for expenses that are reimbursed under Medicare Part D beginning January 1, 2013. The federal deferred tax expense for 2009 primarily resulted from the bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009.

For the nine months ended September 30, 2010, the effective tax rate was 39.6 percent (33.8 percent for the nine months ended September 30, 2009). Excluding additional tax expense recorded as a result of the Patient Protection and Affordable Care Act, the 2010 effective tax rate was 35.7 percent. The 2010 effective tax rate, excluding the additional tax expense recorded as a result of the Patient Protection and Affordable Care Act, deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC-Equity, investment tax credits, wind production tax credits, and depletion. The 2010 effective tax rate was also favorably impacted by $0.8 million for the completion of a state income tax audit.

Uncertain Tax Positions. As of September 30, 2010, we have gross unrecognized tax benefits of $13.5 million. Of this total, $0.7 million represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate.

We expect that the total amount of unrecognized tax benefits as of September 30, 2010, will change by an immaterial amount in the next 12 months.

Other Comprehensive Income

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Other Comprehensive Income

NOTE 10. OTHER COMPREHENSIVE INCOME

The components of other comprehensive income were as follows:

	Quarter Ended		Nine Months Ended
	September 30,		September 30,
Other Comprehensive Income (Loss)	2010	2009	2010	2009
Millions
Net Income	$19.5	$15.8	$61.7	$42.0
Other Comprehensive Income
Unrealized Gain (Loss) on Securities Net of income taxes of $0.3, $0.7, $(0.1), and $1.3	0.4	1.0	(0.1)	1.9
Unrealized Loss on Derivatives Net of income taxes of $–, $–, $–, and $–	–	0.1	–	–
Defined Benefit Pension and Other Postretirement Plans Net of income taxes of $0.2, $0.1, $0.7, and $0.5	0.3	0.1	0.9	0.7
Total Other Comprehensive Income	0.7	1.2	0.8	2.6
Total Comprehensive Income	$20.2	$17.0	$62.5	$44.6
Less: Non-Controlling Interest in Subsidiaries	(0.1)	(0.2)	(0.3)	(0.3)
Comprehensive Income Attributable to ALLETE	$20.3	$17.2	$62.8	$44.9

- Definition

This label may include the following: 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income. Components of comprehensive income include: (1) foreign currency translation adjustments; (2) gains and losses on foreign currency transactions that are designated as, and are effective as, economic hedges of a net investment in a foreign entity; (3) gains and losses on intercompany foreign currency transactions that are of a long-term-investment nature, when the entities to the transaction are consolidated, combined, or accounted for by the equity method in the reporting enterprise's financial statements; (4) change in the market value of a futures contract that qualifies as a hedge of an asset reported at fair value; (5) unrealized holding gains and losses on available-for-sale securities and that resulting from transfers of debt securities from the held-to-maturity category to the available-for-sale category; (6) a net loss recognized as an additional pension liability not yet recognized as net periodic pension cost; and (7) the net gain or loss and net prior service cost or credit for pension plans and other postretirement benefit plans.

+ References+ Details

EarningsPerShareAndCommonStock

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Earnings Per Share and Common Stock

NOTE 11. EARNINGS PER SHARE AND COMMON STOCK

The difference between basic and diluted earnings per share, if any, arises from outstanding stock options and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. For the quarter and nine months ended September 30, 2010, 0.5 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices, and therefore, their effect would have been anti-dilutive. For the quarter and nine months ended September 30, 2009, 0.6 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share.

		2010			2009
Reconciliation of Basic and Diluted		Dilutive			Dilutive
Earnings Per Share	Basic	Securities	Diluted	Basic	Securities	Diluted
Millions Except Per Share Amounts
For the Quarter Ended September 30,
Net Income Attributable to ALLETE	$19.6		$19.6	$16.0		$16.0
Common Shares	34.4	0.1	34.5	32.8	0.1	32.9
Earnings Per Share	$0.57		$0.56	$0.49		$0.49

For the Nine Months Ended September 30,
Net Income Attributable to ALLETE	$62.0		$62.0	$42.3		$42.3
Common Shares	34.1	0.1	34.2	31.8	0.1	31.9
Earnings Per Share	$1.82		$1.81	$1.33		$1.33

Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Pension and Other Postretirement Benefit Plans

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

	Pension		Other Postretirement
Components of Net Periodic Benefit Expense	2010	2009	2010	2009
Millions
For the Quarter Ended September 30,
Service Cost	$1.5	$1.4	$1.2	$1.0
Interest Cost	6.6	6.5	2.7	2.5
Expected Return on Plan Assets	(8.4)	(8.4)	(2.4)	(2.0)
Amortization of Prior Service Costs	0.1	0.1	–	–
Amortization of Net Loss	1.6	0.9	1.2	0.6
Amortization of Transition Obligation	–	–	0.6	0.6
Net Periodic Benefit Expense	$1.4	$0.5	$3.3	$2.7

	Pension		Other Postretirement
Components of Net Periodic Benefit Expense	2010	2009	2010	2009
Millions
For the Nine Months Ended September 30,
Service Cost	$4.6	$4.3	$3.6	$3.1
Interest Cost	19.7	19.6	8.2	7.5
Expected Return on Plan Assets	(25.2)	(25.3)	(7.2)	(6.2)
Amortization of Prior Service Costs	0.3	0.4	–	–
Amortization of Net Loss	4.9	2.6	3.6	1.8
Amortization of Transition Obligation	–	–	1.8	1.9
Net Periodic Benefit Expense	$4.3	$1.6	$10.0	$8.1

Employer Contributions. For the nine months ended September 30, 2010, $1.5 million was contributed to our defined benefit pension plan. (For the nine months ended September 30, 2009, $32.9 million was contributed of which $12.0 million was contributed through the issuance of 463,000 shares of ALLETE common stock.) For the nine months ended September 30, 2010, we contributed $12.4 million to our other postretirement benefit plan ($9.3 million for the nine months ended September 30, 2009). We do not expect to make any additional contributions to our defined benefit pension plan in 2010; however, we expect to make additional contributions of approximately $1 million to our other postretirement benefit plan in 2010.

We provide postretirement health benefits that include prescription drug benefits which qualify us for the federal subsidy under the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The expected reimbursement for Medicare health subsidies reduced our postretirement medical expense by $1.3 million for 2010 ($2.0 million for 2009). For the nine months ended September 30, 2010, we have not received any prescription drug reimbursements.

- Definition

Description containing the entire pension and other postretirement benefits disclosure as a single block of text.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7, 21, 22

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

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-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

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-Number 106

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-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

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-Number 132R

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-Number 132R

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-Number 132R

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-Name Emerging Issues Task Force (EITF)

-Number 03-2

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-Name Accounting Principles Board Opinion (APB)

-Number 30

-Paragraph 26

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-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

+ Details

Commitments, Guarantees and Contingencies

9 Months Ended

Sep. 30, 2010

Notes To Financial Statements [Abstract]

Commitments, Guarantees and Contingencies

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

Square Butte PPA. Minnesota Power has a power purchase agreement 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 power pool 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 discussed on page 22. 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. We expect debt service, operating and maintenance and depreciation expenses to increase in 2011 due to environmental compliance obligations. As of September 30, 2010, Square Butte had total debt outstanding of $321.3 million. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, our subsidiary, under a long-term contract.

Minnkota Power Sales Agreement. In conjunction with the purchase of the existing 250 kV DC transmission line from Square Butte on December 31, 2009, Minnesota Power entered into a contingent 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, resulting in Minnkota’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.

No power will be sold under this agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in 2013. This new AC transmission line will allow Minnkota to transmit its entitlement from Square Butte directly to its customers, and allow Minnesota Power additional capacity on the recently acquired DC line to transmit new wind generation.

Wind PPA. In 2006 and 2007, we entered into two long-term wind PPA with an affiliate of NextEra Energy, Inc. to purchase the output from two wind facilities, Oliver Wind I (50 MWs) and Oliver Wind II (48 MWs), located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities at fixed prices.

Hydro PPA. We have a PPA with Manitoba Hydro that began in May 2009 and expires in April 2015. Under the agreement with Manitoba Hydro, Minnesota Power purchases 50 MWs 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.

On April 30, 2010, Minnesota Power signed a definitive agreement with Manitoba Hydro, subject to MPUC approval, to purchase surplus energy beginning in May 2011 through April 2022. This energy-only transaction primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement with Manitoba Hydro, Minnesota Power will be purchasing at least one million MWh of energy over the contract term. On September 1, 2010, we filed a petition with the MPUC to approve our PPA with Manitoba Hydro.

North Dakota Wind Project. On December 31, 2009, we purchased an existing 250 kV DC transmission line from Square Butte for $69.7 million. The 465-mile transmission line runs from Center, North Dakota, to Duluth, Minnesota. We expect to use this line to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit.

Bison I, with a nameplate capacity of approximately 76 MWs, is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will help fulfill the Minnesota 2025 renewable energy supply requirement for our retail load. In 2009, the NDPSC authorized site construction for Bison I and on March 10, 2010, approved the construction of a 22-mile, 230 kV transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. In 2009, the MPUC approved Minnesota Power’s petition seeking current cost recovery eligibility for investments and expenditures related to Bison I and associated transmission upgrades. On July 21, 2010, the MPUC approved our petition establishing rates effective August 1, 2010.

Bison I, including the associated transmission upgrades to the DC Line, will have a total capital cost of approximately $177 million. As of September 30, 2010, total costs incurred were approximately $101 million. The 22-mile, 230 kV transmission line has been completed and 16 wind turbines have been installed and will be phased into service through the end of 2010. The remaining turbines will be installed in 2011.

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 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 $8.8 million in 2010, $8.9 million in 2011, $9.0 million in 2012, $8.5 million in 2013, $8.2 million in 2014 and $45.7 million thereafter.

Coal, Rail and Shipping Contracts. We have coal supply agreements and transportation agreements providing for the purchase and delivery of a significant portion of our coal requirements. These coal and transportation agreements, including option terms, expire in various years between 2010 and 2015. Our remaining minimum payment obligation as of September 30, 2010, under these coal, rail and shipping agreements is $7.6 million for 2010. Our minimum annual payment obligation for 2011 is $7.4 million, 2012 is $1.6 million, and 2013 is $1.3 million. 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.

CapX2020 Transmission Projects. Minnesota Power is a participant in the CapX2020 initiative which is an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipals and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region's transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project by project basis.

Minnesota Power initially plans to participate in three CapX2020 projects: the Fargo to St. Cloud project, the Monticello to St. Cloud project, which together total a 238-mile, 345 kV line from Fargo to Monticello, and the 70-mile, 230 kV line between Bemidji and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015. As CapX2020 project costs are eligible for current cost recovery, the Company has petitioned the MPUC to recover those costs under a transmission cost recovery tariff rider.

In July 2010, the MPUC granted a route permit for the 28-mile 345 kV transmission line between Monticello and St. Cloud. Construction of the project is expected to be complete in late 2011. The 210-mile 345 kV transmission line from St. Cloud to Fargo is expected to be complete by 2015.

Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes are under consideration by both Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have been a focus of these discussions. Minnesota Power’s fossil fueled facilities will likely be subject to regulation under these climate change policies. Our intention is to reduce our exposure to possible future carbon and GHG legislation by reshaping our generation portfolio, over time, to reduce our reliance on coal.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments.

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. These accruals are adjusted periodically 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.

Clean Air Act. The federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2 and system-wide average NOX limits. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of these facilities are equipped with pollution control equipment such as scrubbers, bag houses, or electrostatic precipitators. Minnesota Power’s generating facilities are currently in compliance with applicable emission requirements.

New Source Review. In August 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR) requirements of the Clean Air Act at Boswell Units 1-4 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. Minnesota Power believes the projects were in full compliance with the Clean Air Act, NSR requirements and applicable permits.

We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Since 2006, Minnesota Power has significantly reduced emissions at Laskin and Boswell, and continues to reduce emissions at Boswell. The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unable to predict the ultimate financial impact or the resolution of these matters at this time.

EPA Transport Rule. On July 6, 2010, the EPA proposed a rule known as the Transport Rule (TR) requiring 31 states, including Minnesota and the District of Columbia, to reduce power plant SO2 and NOx emissions that can significantly contribute to ozone and fine particle pollution problems in other states. If adopted, the TR will replace the Clean Air Interstate Rule (CAIR) that was issued by the EPA in March 2005. CAIR sought to reduce and permanently cap emissions of SO2, NOx, and particulates in the eastern United States. Minnesota was included as one of the original 28 CAIR states but, following Minnesota Power’s successful challenge to CAIR, the EPA granted an administrative stay of the CAIR requirements in Minnesota while it prepared the TR. The proposed TR responds to the United States Court of Appeals for the District of Columbia Circuit’s remand of CAIR by replacing and reforming questionable provisions to address updated air quality standards, improved emissions data and reformed emissions transport modeling.

The EPA took public comments on the proposed rule through October 1, 2010, and plans to finalize the rule in June 2011. Emissions reductions are proposed to take effect in 2012, within one year of projected finalization of the rule.

The EPA has not yet determined whether trading of emission allowances between regulated generating units or states may be implemented. Since 2005, we have made substantial investments in pollution control equipment at our Laskin, Taconite Harbor and Boswell generating units which have significantly reduced emissions. These reductions may satisfy Minnesota Power’s obligations with respect to these requirements. We are unable to predict any additional compliance costs we might incur at this time.

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

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007 the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was not filed at that time due to the United States Court of Appeals for the District of Columbia Circuit’s remand of CAIR. Subsequently, the MPCA requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which was completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirement for that unit. In December 2009, the MPCA approved the SIP for submittal to the EPA for its review and approval. The EPA is expected to make a decision on whether to approve the Minnesota SIP by January 2011. If approved, Minnesota Power will have five years to bring Taconite Harbor Unit 3 into compliance. It is uncertain what controls will ultimately be required at Taconite Harbor Unit 3 in connection with the regional haze rule.

EPA National Emission Standards for Hazardous Air Pollutants (NESHAPs) for Electric Utility Units. Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants for certain source categories. In December 2009, Minnesota Power and other utilities received an Information Collection Request from the EPA requiring that emissions data be provided and stack testing be performed in order to develop a database upon which to base future regulations. On March 30, 2010, Minnesota Power responded to the Information Collection Request. Stack testing was completed during the third quarter of 2010 and the results were submitted to the EPA. The EPA is subject to a consent decree which requires the EPA to propose a utility NESHAPs rule by March 2011, with the final rule by November 2011. As part of the NESHAPs rulemaking, EPA will develop Maximum Achievable Control Technology standards for utilities. Costs for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Act cannot be estimated at this time.

Minnesota Mercury Emission Reduction Act. Under Minnesota law, a mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2015, with implementation no later than December 31, 2018. The statute also calls for an evaluation of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’s customers. Costs for the Boswell Unit 4 emission reduction plan cannot be estimated at this time.

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

Ozone NAAQS. The EPA is attempting to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA expects to issue final standards by 2011. As proposed, states have until December 2013 to submit plans outlining how they will meet the standards.

Particulate Matter NAAQS. The EPA finalized the NAAQS Particulate Matter standards in September 2006, by establishing a more stringent 24-hour average fine particulate (PM2.5) standard and keeping the annual average fine particulate matter standard and the 24-hour coarse particulate matter standard unchanged. The District of Columbia Circuit Court of Appeals has remanded the PM2.5 standard to the EPA, requiring consideration of lower annual average standard values. The EPA has indicated that air quality monitoring for 2008 through 2010 will be used as a basis for states to characterize their attainment status. The EPA plans to finalize the new PM2.5 standards in 2011, and state attainment status determination will likely not occur prior to 2013.

SO2 and NO2 NAAQS. The EPA recently finalized a new one-hour NAAQS for SO2 and NO2. Monitor data indicates that Minnesota will likely be in compliance with these new standards; however, the SO2 NAAQS also requires the EPA to evaluate modeling data to determine attainment. It is unclear what the outcome of this evaluation will be. These NAAQS could result in more stringent emission limits on our steam generating facilities. The final compliance status for SO2 is expected in 2012, with compliance required by August 2017. The compliance status for NO2 is not expected until 2016 or 2017, following the installation of additional air quality monitors and the collection and analysis of additional air quality data.

We are unable to predict the nature or timing of any additional NAAQS regulation or compliance costs we might incur at this time.

Climate Change. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customer’s requirements:

·	Expand our renewable energy supply.

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

·	Provide energy conservation initiatives for our customers and engage in other demand side efforts.

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

·	Achieve overall carbon emission reductions.

The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. These physical risks could include, but are not limited to, increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations.

Federal Legislation. We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the federal level to “cap” the amount of GHG emissions have been made. In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap-and-trade program. H.R. 2454 allocates a significant number of emission allowances to the electric utility sector to mitigate cost impacts on consumers. Based on the emission allowance allocations proposed in H.R. 2454, we expect we would have to purchase additional allowances. At this time we are unable to predict the cost of these allowances.

In September 2009, the Senate introduced S. 1733, the Senate version of H.R. 2454. This proposed legislation features a more stringent, near-term greenhouse emissions reduction target in 2020, of 20 percent below 2005 levels, as compared to the 17 percent reduction proposed by H.R. 2454. Another cap and trade proposal introduced in the Senate on May 12, 2010, referred to as the American Power Act, carries similar emission reduction targets to S. 1733 while modifying allowance distribution mechanisms. The Senate is also considering a national renewable energy standard that may serve as a step in addressing climate and energy policy.

Congress may consider proposals other than cap-and-trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454, S. 1733, or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company. We also cannot predict the nature or timing of any additional GHG legislation or regulation.

Minnesota Greenhouse Gas Reduction and Emissions Reporting. In 2007, Minnesota passed legislation establishing non-binding targets for carbon dioxide reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050. In May 2008, Minnesota passed legislation that required the MPCA to track emissions and make interim emissions reduction recommendations towards meeting the State’s goal.

Midwestern Greenhouse Gas Reduction Accord. Minnesota is also participating in the Midwestern Greenhouse Gas Reduction Accord (the Accord), a regional effort to develop a multi-state approach to GHG emission reductions. The Accord includes an agreement to develop a multi-sector cap-and-trade system to help meet the targets established by the group.

International Climate Change Initiatives. The United States is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) that requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. In December 2009, leaders of developed and developing countries met in Copenhagen, Denmark, under the UNFCCC and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHG by 2020, and provides for developed countries to fund GHG emissions mitigation projects in developing countries. President Obama participated in the development of, and endorsed, the Copenhagen Accord.

EPA Greenhouse Gas Reporting Rule. In September 2009, the EPA issued a final rule mandating that certain GHG emission sources, including electric generating units and gas distribution companies (such as SWL&P), are required to report GHG emissions. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis beginning March 31, 2011. We have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.

EPA Regulation of GHG Emissions. In December 2009, the EPA issued an “Endangerment Finding” with respect to emissions of GHGs. The Endangerment Finding was the EPA’s published determination that six GHGs endanger human health or welfare, and that emissions from motor vehicles contribute to that endangerment. The EPA’s exercise of authority over GHG emissions through the Endangerment Finding triggered the EPA’s regulation of stationary sources for GHGs under the Clean Air Act.

On May 13, 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule. The PSD/Title V Greenhouse Gas Tailoring Rule establishes thresholds for when permits will be required to address GHG emissions for new facilities, at existing facilities that undergo major modifications, and at other facilities that are characterized as major sources under the Clean Air Act’s Title V program. Under the new rule, existing sources of emissions that already have a Title V permit would have GHG provisions added to their permits upon renewal. The rule requires large industrial facilities, including power plants, that undergo major modifications resulting in a significant increase in GHG emissions to obtain PSD permits that demonstrate that Best Available Control Technology (BACT) is being used at the facility to control GHG emissions. The EPA has defined significant emissions increase for existing sources as a GHG increase of 75,000 tons per year or more of total GHG on a CO2 equivalent basis. The EPA is expected to propose BACT standards for GHG emissions from stationary sources in late 2010.

For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHGs requirements. Implementation of that requirement to add GHG provisions will be completed at the state level in Minnesota by the MPCA when the Title V permits are renewed. However, installation of new units or modification of existing units resulting in a significant increase in GHG emissions will require obtaining PSD permits and amending our operating permits to incorporate BACT to control GHG emissions. Minnesota Power’s existing facilities become subject to the BACT requirements if they undergo major modifications that result in a significant emissions increase. Legal challenges to the EPA’s regulation of GHG emissions, including the Tailoring Rule, have been filed and are awaiting judicial determination.

We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its steam electric stations. 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. On June 18, 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal seeks comments on two general regulatory schemes for coal ash. Comments are due to the EPA by November 18, 2010. We are unable to predict the compliance costs we might incur; however, there is the possibility they could have a material impact.

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City of Superior, Wisconsin, and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At September 30, 2010, we have a $0.5 million liability for this site, and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.

Other Matters

BNI Coal. As of September 30, 2010, BNI Coal had surety bonds outstanding of $18.4 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, an additional guarantee 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 $10.0 million. The combination of the surety bonds and the Letter of Credit is sufficient to meet the requirements to guarantee BNI Coal’s total reclamation liability, currently estimated at $25.1 million.

ALLETE Properties. As of September 30, 2010, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $12.9 million primarily related to performance and maintenance obligations to governmental entities to construct improvements in the Company’s various projects. The remaining work to be completed on these improvements is estimated to be approximately $9.0 million, and ALLETE Properties does not believe it is likely that any of these outstanding bonds 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, Series 2005; and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent Special Assessment Bonds, Series 2006. The Capital Improvement Revenue Bonds and the Special Assessment Bonds are payable through property tax assessments on the land owners over 31 years (by May 1, 2036, and 2037, respectively). 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 bonds are payable from and secured by the revenue derived from annual assessments imposed, levied and collected by each district. The assessments are being billed annually to the landowners. To the extent that we own land at the time of the annual assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. As of September 30, 2010, we owned 69 percent of the assessable land in the Town Center District (69 percent as of December 31, 2009) and 93 percent of the assessable land in the Palm Coast Park District (86 percent as of December 31, 2009). At these ownership levels our annual assessments are approximately $1.5 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. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.

Other. We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base and cost of service issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these matters are expected to materially change our present liquidity position, or have a material adverse effect on our financial condition.

Document Information	9 Months Ended
Document Information	Sep. 30, 2010
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2010

Entity Information (USD $)	9 Months Ended
Entity Information (USD $)	Sep. 30, 2010	Jun. 30, 2009
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 974,440,368
Entity Common Stock, Shares Outstanding	35,799,762
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	Q3