Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2010	Dec. 31, 2009
Current Assets
Cash and Cash Equivalents	$ 44.9	$ 25.7
Short-Term Investments	6.7	0
Accounts Receivable (Less Allowance of $0.9 and $0.9)	99.5	118.5
Inventories	60.0	57.0
Prepayments and Other	28.6	24.3
Total Current Assets	239.7	225.5
Property, Plant and Equipment - Net	1,805.6	1,622.7
Regulatory Assets	310.2	293.2
Investment in ATC	93.3	88.4
Other Investments	126.0	130.5
Other Non-Current Assets	34.3	32.8
Total Assets	2,609.1	2,393.1
Current Liabilities
Accounts Payable	75.4	62.1
Accrued Taxes	22.0	20.6
Accrued Interest	13.4	11.1
Long-Term Debt Due Within One Year	13.4	5.2
Notes Payable	1.0	1.9
Other	33.7	32.2
Total Current Liabilities	158.9	133.1
Long-Term Debt	771.6	695.8
Deferred Income Taxes	325.2	253.1
Regulatory Liabilities	43.6	47.1
Other Non-Current Liabilities	324.8	325.0
Total Liabilities	1,624.1	1,454.1
ALLETE's Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 35.8 and 35.2 Shares Outstanding	636.1	613.4
Unearned ESOP Shares	(36.8)	(45.3)
Accumulated Other Comprehensive Loss	(23.2)	(24.0)
Retained Earnings	399.9	385.4
Total ALLETE Equity	976.0	929.5
Non-Controlling Interest in Subsidiaries	9.0	9.5
Total Equity	985.0	939.0
Total Liabilities and Equity	$ 2,609.1	$ 2,393.1

Consilidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Operating Revenue
Operating Revenue	$ 907.0	$ 766.7	$ 801.0
Prior Year Rate Refunds	0	(7.6)	0
Total Operating Revenue	907.0	759.1	801.0
Operating Expenses
Fuel and Purchased Power	325.1	279.5	305.6
Operating and Maintenance	365.6	308.9	318.1
Depreciation	80.5	64.7	55.5
Total Operating Expenses	771.2	653.1	679.2
Operating Income	135.8	106.0	121.8
Other Income (Expense)
Interest Expense	(39.2)	(33.8)	(26.3)
Equity Earnings in ATC	17.9	17.5	15.3
Other	4.6	1.8	15.6
Total Other Income (Expense)	(16.7)	(14.5)	4.6
Income Before Non-Controlling Interest and Income Taxes	119.1	91.5	126.4
Income Tax Expense	44.3	30.8	43.4
Net Income	74.8	60.7	83.0
Less: Non-Controlling Interest in Subsidiaries	(0.5)	(0.3)	0.5
Net Income Attributable to ALLETE	$ 75.3	$ 61.0	$ 82.5
Average Shares of Common Stock
Basic (in shares)	34.2	32.2	29.2
Diluted (in shares)	34.3	32.2	29.3
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 2.20	$ 1.89	$ 2.82
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 2.19	$ 1.89	$ 2.82
Dividends Per Share of Common Stock (in dollars per share)	$ 1.76	$ 1.76	$ 1.72

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Operating Activities
Net Income	$ 74.8	$ 60.7	$ 83.0
Allowance for Funds Used During Construction	(4.2)	(5.8)	(3.3)
Loss (Income) from Equity Investments, Net of Dividends	(3.1)	0.1	(3.1)
Gain on Real Estate Foreclosure	(0.7)	0	0
Gain on Sale of Assets	0	(0.2)	(4.8)
Gain on Sale of Available-for-sale Securities	0	0	(6.4)
Loss on Impairment of Assets	0	3.1	0
Depreciation Expense	80.5	64.7	55.5
Amortization of Debt Issuance Costs	0.9	0.9	0.8
Deferred Income Tax Expense	66.0	75.2	38.8
Share-Based Compensation Expense	2.2	2.1	1.8
ESOP Compensation Expense	7.1	6.5	10.1
Bad Debt Expense	1.1	1.3	0.7
Changes in Operating Assets and Liabilities
Accounts Receivable	17.9	(43.5)	2.4
Inventories	(3.0)	(7.3)	(0.2)
Prepayments and Other	(4.3)	0	11.2
Accounts Payable	5.8	10.5	(14.1)
Other Current Liabilities	5.2	5.3	5.9
Regulatory and Other Assets	16.3	(18.3)	(1.8)
Regulatory and Other Liabilities	(33.8)	(17.9)	(22.9)
Cash from Operating Activities	228.7	137.4	153.6
Investing Activities
Proceeds from Sale of Available-for-sale Securities	0.6	8.9	62.3
Payments for Purchase of Available-for-sale Securities	(2.3)	(2.2)	(44.8)
Investment in ATC	(1.6)	(7.8)	(7.4)
Changes to Other Investments	1.3	(0.7)	(9.2)
Additions to Property, Plant and Equipment	(248.9)	(318.5)	(301.1)
Proceeds from Sale of Assets	0	0.3	20.4
Other	0	0	3.7
Cash for Investing Activities	(250.9)	(320.0)	(276.1)
Financing Activities
Proceeds from Issuance of Common Stock	20.5	65.2	71.1
Proceeds from Issuance of Long-Term Debt	155.0	111.4	198.7
Changes in Notes Payable	(0.9)	(4.1)	6.0
Reductions of Long-Term Debt	(71.0)	(9.1)	(22.7)
Debt Issuance Costs	(1.4)	(0.6)	(1.5)
Dividends on Common Stock	(60.8)	(56.5)	(50.4)
Cash from Financing Activities	41.4	106.3	201.2
Change in Cash and Cash Equivalents	19.2	(76.3)	78.7
Cash and Cash Equivalents at Beginning of Period	25.7	102.0	23.3
Cash and Cash Equivalents at End of Period	44.9	25.7	102.0
Profit Loss	$ 74.8	$ 60.7	$ 83.0

Consolidated Statement of Shareholders' Equity (USD $) In Millions, unless otherwise specified	Total	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Unearned ESOP Shares	Common Stock
Total Shareholders' Equity at Dec. 31, 2007	$ 742.6	$ 350.4	$ (4.5)	$ (64.5)	$ 461.2
Comprehensive Income
Net Income	83.0	83.0	0	0	0
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	(6.0)	0	(6.0)	0	0
Reclassification Adjustment for Gains Included in Income	(3.7)	0	(3.7)	0	0
Defined Benefit Pension and Other Postretirement Plans	(18.8)	0	(18.8)	0	0
Total Comprehensive Income	54.5	0	0	0	0
Non-Controlling Interest in Subsidiaries	(0.5)	(0.5)	0	0	0
Comprehensive Income Attributable to ALLETE	54.0	0	0	0	0
Adjustment to apply change in Pension and Postretirement measurement date	(1.6)	(1.6)	0	0	0
Common Stock Issued - Net	72.9	0	0	0	72.9
Dividends Declared	(50.4)	(50.4)	0	0	0
ESOP Shares Earned	9.6	0	0	9.6	0
Total Shareholders' Equity at Dec. 31, 2008	827.1	380.9	(33.0)	(54.9)	534.1
Comprehensive Income
Net Income	60.7	60.7	0	0	0
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	2.8	0	2.8	0	0
Defined Benefit Pension and Other Postretirement Plans	6.2	0	6.2	0	0
Total Comprehensive Income	69.7	0	0	0	0
Non-Controlling Interest in Subsidiaries	0.3	0.3	0	0	0
Comprehensive Income Attributable to ALLETE	70.0	0	0	0	0
Common Stock Issued - Net	79.3	0	0	0	79.3
Dividends Declared	(56.5)	(56.5)	0	0	0
ESOP Shares Earned	9.6	0	0	9.6	0
Total Shareholders' Equity at Dec. 31, 2009	929.5	385.4	(24.0)	(45.3)	613.4
Comprehensive Income
Net Income	74.8	74.8	0	0	0
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	0.8	0	0.8	0	0
Total Comprehensive Income	75.6	0	0	0	0
Non-Controlling Interest in Subsidiaries	0.5	0.5	0	0	0
Comprehensive Income Attributable to ALLETE	76.1	0	0	0	0
Common Stock Issued - Net	22.7	0	0	0	22.7
Dividends Declared	(60.8)	(60.8)	0	0	0
ESOP Shares Earned	8.5	0	0	8.5	0
Total Shareholders' Equity at Dec. 31, 2010	$ 976.0	$ 399.9	$ (23.2)	$ (36.8)	$ 636.1

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Operations and Significant Accounting Policies

Note 1.

Operations and Significant Accounting Policies

Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue, and expenses. Actual results could differ from those estimates.

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

Principles of Consolidation. Our consolidated financial statements include the accounts of ALLETE and all of our majority-owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

Business Segments. Our Regulated Operations and Investments and Other segments were determined in accordance with the guidance on segment reporting. Segmentation is based on the manner in which we operate, assess, and allocate resources to the business. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes retail and wholesale rate-regulated electric, natural gas, and water services in northeastern Minnesota and northwestern Wisconsin along with our Investment in ATC. Minnesota Power provides regulated utility electric service to 146,000 retail customers in northeastern Minnesota. SWL&P, a wholly-owned subsidiary, provides regulated utility electric, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Our Investment in ATC includes our approximate 8 percent equity ownership interest in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. (See Note 6. Investment in ATC.)

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 available-for-sale in Minnesota, and earnings on cash and investments.

BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2010, Square Butte supplied approximately 50 percent (227.5 MW) of its output to Minnesota Power under a long-term contract. (See Note 10. Commitments, Guarantees and Contingencies.) Coal sales are recognized when delivered at the cost of production plus a specified profit per ton of coal delivered.

ALLETE Properties is our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell the portfolio over time or in bulk transactions.

Full profit recognition is recorded on sales upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate, are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

In certain cases, we pay fees or construct improvements to mitigate offsite traffic impacts. In return, we receive traffic impact fee credits as a result of some of these expenditures. We recognize revenue from the sale of traffic impact fee credits when payment is received.

Land held-for-sale is recorded at the lower of cost or fair value determined by the evaluation of individual land parcels and is included in Other Investments on our consolidated balance sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with the accounting standards for real estate. The cost of real estate includes the actual costs incurred and the estimate of future completion costs allocated to the real estate sold based upon the relative sales value method. Whenever events or circumstances indicate that the carrying value of the real estate may not be recoverable, impairments would be recorded and the related assets would be adjusted to their estimated fair value, less costs to sell. (See Note 7. Investments.)

Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Supplemental Statement of Cash Flow Information

Consolidated Statement of Cash Flows
Supplemental Disclosure
Year Ended December 31	2010	2009	2008
Millions
Cash Paid During the Period for
Interest – Net of Amounts Capitalized	$35.7	$29.8	$25.2
Income Taxes (Net of refunds received of $57.1, $6.7 and $–) (a)	$(54.2)	$(5.6)	$6.5

Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$7.5	$(24.1)	$17.1
AFUDC – Equity	$4.2	$5.8	$3.3
ALLETE Common Stock contributed to the 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 NOL which was utilized by carrying it back against prior years’ taxable income and the completion of a state income tax audit.

Accounts Receivable. Accounts receivable are reported on the balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses.

Accounts Receivable
As of December 31	2010	2009
Millions
Trade Accounts Receivable
Billed	$67.6	$56.5
Unbilled	18.9	15.1
Less: Allowance for Doubtful Accounts	0.9	0.9
Total Trade Accounts Receivable	85.6	70.7
Income Taxes Receivable	13.9	47.8
Total Accounts Receivable – Net	$99.5	$118.5

Concentration of Credit Risk. Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to 10 Large Power Customers. Receivables from these customers totaled $17.3 million at December 31, 2010 ($9.6 million at December 2009). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, our taconite-producing Large Power Customers are on a weekly billing cycle, which allows us to closely manage collection of amounts due.

Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivable to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals. (See Note 7. Investments.)

Available-for-Sale Securities. Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as the share price trends and the impact of overall market conditions. (See Note 7. Investments.)

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

Inventories
As of December 31	2010	2009
Millions
Fuel	$22.9	$23.0
Materials and Supplies	37.1	34.0
Total Inventories	$60.0	$57.0

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the balance sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on non-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. However, the MPUC has approved current cost recovery for several large capital projects recently, resulting in lower recognition of AFUDC. (See Note 3. Property, Plant and Equipment.)

Long-Lived Asset Impairments. We account for our long-lived assets at depreciated historical cost. A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. We conduct this assessment in accordance with the accounting standards for impairment or disposal of long-lived assets. Judgments and uncertainties affecting the application of accounting for asset impairment include economic conditions affecting market valuations, changes in our business strategy, and changes in our forecast of future operating cash flows and earnings. We would recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted future cash flows. Management judgment is involved in both deciding if testing for recoverability is necessary and in estimating undiscounted future cash flows.

Derivatives. We review all material power purchase and sales contracts for derivative treatment to determine if they qualify for the normal purchase normal sale exception under the guidance for derivatives and hedging.

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 16. Employee Stock and Incentive Plans.)

Prepayments and Other Current Assets
As of December 31	2010	2009
Millions
Deferred Fuel Adjustment Clause (See Note 5. Regulatory Matters)	$20.6	$15.5
Other	8.0	8.8
Total Prepayments and Other Current Assets	$28.6	$24.3

Other Non-Current Liabilities
As of December 31	2010	2009
Millions
Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Plans	$231.4	$231.2
Asset Retirement Obligation (See Note 3. Property, Plant and Equipment)	50.3	44.6
Other	43.1	49.2
Total Other Non-Current Liabilities	$324.8	$325.0

Environmental Liabilities. We review environmental matters for disclosure 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 becomes available. Accruals for environmental liabilities are included in the 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 operating expense unless recoverable in rates from customers. (See Note 10. Commitments, Guarantees and Contingencies.)

Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain environmental and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause.

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using the straight-line method.

Income Taxes. We file a consolidated federal income tax return. We account for income taxes using the liability method in accordance with the accounting standards for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 percent likely. (See Note 13. Income Tax Expense.)

Excise Taxes. We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.

Recently Adopted 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 was adopted December 31, 2010, and did not have an impact on our consolidated financial position, results of operations or cash flows. The guidance for the roll forward requirement 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.

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 December 31, 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.

Regulatory Matters

12 Months Ended

Dec. 31, 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 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 were approximately $52 million for 2010.

On November 2, 2010, Minnesota Power received a written order from the MPUC approving a retail rate increase of approximately $54 million, a 10.38 percent return on common equity and a 54.29 percent equity ratio, subject to reconsideration. In a hearing on January 19, 2011, the MPUC denied all reconsideration requests. Final rates will be implemented after acceptance of the compliance filing, estimated in the second quarter of 2011. Minnesota Power will continue to collect interim rates from its customers until the new rates go into effect. We expect no interim rate refunds will be issued.

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 formula-based rate contracts with these customers. The rates included in these contracts are calculated using a cost-based formula methodology that is set at the beginning of the year using estimated costs, and provides for a true-up calculation for actual costs. The estimated true-up is recorded in the current year, then finalized and billed or paid to customers in the following year. The contracts include a termination clause requiring a 3 year notice to terminate. To date, no termination notices have been received.

2010 Wisconsin Rate Increase. During 2010, SWL&P’s retail rates were based on a 2008 PSCW retail rate order, which was effective January 1, 2009. SWL&P’s 2011 retail rates are based on a 2010 PSCW retail rate order, effective January 1, 2011, and allows for a 10.9 percent return on common equity. The new rates reflect a 2.4 percent average increase in retail utility rates for SWL&P customers (a 12.80 percent increase in water rates, a 2.49 percent increase in natural gas rates and a 0.68 percent increase in electric rates). On an annualized basis, the rate increase will generate approximately $2 million in additional revenue.

Deferred Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance on 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 refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

Deferred Regulatory Assets and Liabilities
As of December 31	2010	2009
Millions
Deferred Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans (a)	$257.9	$235.8
Boswell Unit 3 Environmental Rider (b)	20.5	20.9
Deferred Fuel (c)	20.6	20.8
Income Taxes	17.3	15.7
Asset Retirement Obligation	7.8	6.3
Deferred MISO Costs	0.9	2.4
Premium on Reacquired Debt	1.8	2.0
Other	4.0	4.8
Total Deferred Regulatory Assets	$330.8	$308.7

Deferred Regulatory Liabilities
Income Taxes	$23.4	$25.9
Plant Removal Obligations	16.9	16.9
Other	3.3	4.3
Total Deferred Regulatory Liabilities	$43.6	$47.1

(a)	See Note 15. Pension and Other Postretirement Benefit Plans.

(b)

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 November 2, 2010, the MPUC approved a proposal to move the rider balance to Property, Plant and Equipment to recover in rate base, which will be effective upon a final rate order.

(c)

As of December 31, 2009, under our 2008 rate case, $5 million of this balance related to deferred fuel costs incurred under the former base cost of fuel calculation. During the fourth quarter of 2010, it was determined that the asset was no longer probable of recovery in future utility rates and was therefore written off.

Current and Non-Current Deferred Regulatory Assets and Liabilities
As of December 31	2010	2009
Millions
Total Current Deferred Regulatory Assets (a)	$20.6	$15.5
Total Non-Current Deferred Regulatory Assets	310.2	293.2
Total Deferred Regulatory Assets	$330.8	$308.7
Total Current Deferred Regulatory Liabilities	–	–
Total Non-Current Deferred Regulatory Liabilities	$43.6	$47.1
Total Deferred Regulatory Liabilities	$43.6	$47.1

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

Investments

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Investments

Note 7.

Investments

Investments. At December 31, 2010, our long-term investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits and land held-for-sale in Minnesota.

Other Investments
As of December 31	2010	2009
Millions
ALLETE Properties	$94.0	$93.1
Available-for-sale Securities (a)	25.2	29.5
Other	6.8	7.9
Total Other Investments	$126.0	$130.5

(a)	As of December 31, 2010, our remaining $6.7 million of Auction Rate Securities were classified as short-term as they were called prior to December 31, 2010, and redeemed at carrying value on January 5, 2011.

ALLETE Properties
As of December 31	2010	2009
Millions
Land Held-for-Sale Beginning Balance	$74.9	$71.2
Additions during period:
Deeds to Collateralized Property (a)	9.9	–
Capitalized Improvements and Other	1.2	5.6
Deductions during period: Cost of Real Estate Sold	–	(1.9)
Land Held-for-Sale Ending Balance	86.0	74.9
Long-Term Finance Receivables (net of allowances of $0.8 and $0.4) (a)	3.7	12.9
Other	4.3	5.3
Total Real Estate Assets	$94.0	$93.1

(a)	The deeds to collateralized property resulted primarily from an entity which filed for voluntary Chapter 11 bankruptcy and were recorded at fair value net of estimated selling costs. The change in the long-term finance receivables was primarily a result of the same transaction.

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 year ended December 31, 2010 (none in 2009).

Long-Term Finance Receivables. As of December 31, 2010, long-term finance receivables were $3.7 million net of allowance ($12.9 million net of allowance as of December 31, 2009). 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 December 31, 2010, the reserve balance was due to an impairment of $0.8 million on a delinquent note receivable where the fair value of the collateralized property was less than the note balance ($0.3 million of impairments in 2009). This valuation technique constitutes a Level 3 non-recurring fair value measurement.

If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. In many cases, contract purchasers incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they have substantially more at risk than the deposit.

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.

Available-for-Sale Investments. We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities.

Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	(Loss)	Fair Value

2010	$27.4	$0.2	$(2.4)	$25.2
2009	$33.1	$0.1	$(3.7)	$29.5
2008	$40.5	–	$(7.9)	$32.6

				Net Unrealized
	Net	Gross Realized		Gain (Loss) in Other
Year Ended December 31	Proceeds	Gain	(Loss)	Comprehensive Income

2010	$(1.7)	–	–	$1.4
2009	$6.7	–	–	$4.5
2008	$17.5	$6.5	$(0.1)	$(9.7)

Auction Rate Securities. As of December 31, 2010, our ARS were classified as a short-term investment as the remaining balance of $6.7 million was redeemed at carrying value on January 5, 2011. As of December 31, 2009, our ARS were classified as long-term investments.

- 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).

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Fair Value

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Fair Value

Note 8.

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). The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily mutual fund investments held to fund employee benefits.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. This category includes deferred compensation, fixed income securities, and derivative instruments consisting of cash flow hedges.

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes ARS consisting of guaranteed student loans and derivative instruments consisting of FTRs.

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 December 31, 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.

	At Fair Value as of December 31, 2010
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities	$19.4	–	–	$19.4
Available-for-sale Securities
Corporate Debt Securities	–	$7.5	–	7.5
Debt Securities Issued by States of the United States (ARS) (a)	–	–	$6.7	6.7
Total Available-for-sale Securities	–	7.5	6.7	14.2
Money Market Funds	0.8	–	–	0.8
Total Fair Value of Assets	$20.2	$7.5	$6.7	$34.4

Liabilities:
Deferred Compensation	–	$13.3	–	$13.3
Total Fair Value of Liabilities	–	$13.3	–	$13.3

Total Net Fair Value of Assets (Liabilities)	$20.2	$(5.8)	$6.7	$21.1

(a)	The remaining $6.7 million of ARS were redeemed at carrying value on January 5, 2011.

		Debt Securities
		Issued by the States
Recurring Fair Value Measures		of the United States
Activity in Level 3	Derivatives	(ARS)
Millions
Balance as of December 31, 2009	$0.7	$6.7
Purchases, sales, issuances and settlements, net	(0.7)	–
Level 3 transfers in	–	–
Balance as of December 31, 2010 (a)	–	$6.7

(a)	The remaining $6.7 million of ARS were redeemed at carrying value on January 5, 2011.

	At Fair Value as of December 31, 2009
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities	$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	–	–	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

		Debt Securities
		Issued by the States
Recurring Fair Value Measures		of the United States
Activity in Level 3	Derivatives	(ARS)
Millions
Balance as of December 31, 2008	–	$15.2
Purchases, sales, issuances and settlements, net (a)	$0.7	(8.5)
Level 3 transfers in	–	–
Balance as of December 31, 2009	$0.7	$6.7

(a)	ARS were redeemed during 2009 at carrying value.

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. For the year ended December 31, 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 were based on quoted market prices for the same or similar instruments.

Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2010	$785.0	$796.7
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.

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Short-term and Long-term Debt

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Short-Term and Long-Term Debt

Note 9.

Short-Term and Long-Term Debt

Short-Term Debt. Total short-term debt outstanding as of December 31, 2010, was $14.4 million ($7.1 million at December 31, 2009) and consisted of long-term debt due within one year and notes payable. (See ALLETE consolidated balance sheet.)

As of December 31, 2010, we had bank lines of credit aggregating $154.0 million ($157.0 million at December 31, 2009), the majority of which expire in January 2012. We expect to enter into new bank lines of credit during 2011 to replace the expiring facility. These bank lines of credit are available to provide short-term bank loans and credit support for commercial paper. At December 31, 2010, $1.0 million ($69.2 million at December 31, 2009) was drawn on our lines of credit leaving a $153.0 million balance available for use ($87.8 million at December 31, 2009). In December 2009, we drew $65.0 million on our $150.0 million syndicated revolving credit facility to temporarily fund the purchase of the 250 kV DC transmission line. In February 2010, we issued $80.0 million of First Mortgage Bonds (Bonds) (see Long-Term Debt, below). We used the proceeds from the sale of the Bonds to pay off the outstanding amount drawn on the line, resulting in the $65.0 million borrowing under our line of credit being classified as long-term debt at December 31, 2009.

On November 12, 2009, BNI Coal replaced a $6.0 million Promissory Note and Supplement (Line of Credit) with CoBANK, ACB with a $3.0 million Line of Credit and a $3.0 million term loan with CoBANK, ACB. The Line of Credit was renewed on December 22, 2010, and now expires on November 20, 2012. The Line of Credit is being used for general corporate purposes. As of December 31, 2010, $1.0 million was drawn on the Line of Credit. The $3.0 million term loan has a fixed interest rate of 5.19 percent and is payable in 28 equal quarterly installments commencing January 20, 2010, and ending on October 20, 2016.

Long-Term Debt. The aggregate amount of long-term debt maturing during 2011 is $13.4 million ($3.3 million in 2012; $73.9 million in 2013; $19.5 million in 2014; $16.3 million in 2015; and $658.6 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgages collateralizing various First Mortgage Bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

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 balance 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.

Long-Term Debt
As of December 31	2010	2009
Millions
First Mortgage Bonds
4.86% Series Due 2013	$60.0	$60.0
6.94% Series Due 2014	18.0	18.0
7.70% Series Due 2016	20.0	20.0
8.17% Series Due 2019	42.0	42.0
5.28% Series Due 2020	35.0	35.0
4.85% Series Due 2021	15.0	–
4.95% Pollution Control Series F Due 2022	111.0	111.0
6.02% Series Due 2023	75.0	75.0
4.90% Series Due 2025	30.0	–
5.10% Series Due 2025	30.0	–
5.99% Series Due 2027	60.0	60.0
5.69% Series Due 2036	50.0	50.0
6.00% Series Due 2040	35.0	–
5.82% Series Due 2040	45.0	–
SWL&P First Mortgage Bonds
7.25% Series Due 2013	10.0	10.0
Senior Unsecured Notes 5.99% Due 2017	50.0	50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2012 – 2020	28.3	28.3
Industrial Development Revenue Bonds 6.5% Due 2025	6.0	6.0
Industrial Development Variable Rate Demand Refunding
Revenue Bonds Series 2006 Due 2025	27.8	27.8
Line of Credit Facility (a)	–	65.0
Other Long-Term Debt, 1.0% – 8.0% Due 2011 – 2037	36.9	42.9
Total Long-Term Debt	785.0	701.0
Less: Due Within One Year	13.4	5.2
Net Long-Term Debt	$771.6	$695.8

(a)	A portion of the proceeds from the issuance on February 17, 2010, of $80 million principal amount of First Mortgage Bonds due in 2021, 2025 and 2040, was used to repay the outstanding borrowings on the Line of Credit Facility as of December 31, 2009.

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 December 31, 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 December 31, 2010, ALLETE was in compliance with its financial covenants.

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Commitments, Guarantees and Contingencies

Note 10.

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 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 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 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 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. We expect debt service, operating and maintenance and depreciation expenses for Square Butte to increase in 2011 due to environmental compliance obligations. As of December 31, 2010, Square Butte had total debt outstanding of $379.6 million. Annual debt service for Square Butte is expected to be approximately $39 million in each of the five years, 2011 through 2015. 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.

Minnesota Power’s cost of power purchased from Square Butte during 2010 was $55.2 million ($53.9 million in 2009; $56.7 million in 2008). This reflects Minnesota Power’s pro rata share of total Square Butte costs, based on the 50 percent output entitlement in 2010 (50 percent in 2009; 55 percent in 2008). Included in this amount was Minnesota Power’s pro rata share of interest expense of $10.2 million in 2010 ($11.0 million in 2009; $11.6 million in 2008). 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 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, which, in turn, will provide Minnesota Power with additional capacity on the 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 MW) and Oliver Wind II (48 MW), located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities at fixed prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.

Hydro 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 is currently 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.

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. On October 28, 2010, the OES filed comments recommending approval.

North Dakota Wind Development. 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 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 1 is a two phase, 82 MW wind project in North Dakota. All permitting has been received and the first phase was completed in 2010. Phase one included construction of a 22-mile, 230 kV transmission line and the installation of 16 2.3 MW wind turbines, all of which were in-service at the end of 2010. Phase two is expected to be completed late in 2011 and consists of the installation of 15 3.0 MW wind turbines. Bison 1 is expected to have a total capital cost of approximately $177 million, of which $121 million was spent through December 31, 2010. In 2009, the MPUC approved Minnesota Power’s petition seeking current cost recovery eligibility for investments and expenditures related to Bison 1, and in July 2010, the MPUC approved our petition establishing rates effective August 1, 2010.

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 $8.1 million in 2011, $8.4 million in 2012, $8.5 million in 2013, $8.7 million in 2014, $8.4 million in 2015 and $44.7 million thereafter. Total rent and lease expense was $9.4 million in 2010 ($9.3 million in 2009; $8.5 million in 2008).

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 2011 and 2015. Our minimum annual payment obligation for 2011 is $41.0 million, 2012 is $1.6 million, and 2013 is $1.4 million. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

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

Minnesota Power is currently participating 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, of which $11.3 million was spent through December 31, 2010.

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. Construction for the Bemidji to Grand Rapids 230 kV line project commenced in January 2011.

We have an approved cost recovery rider in place for certain transmission expenditures, and our current billing factor was approved by the MPUC in June 2009. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. In our 2010 rate case we moved completed transmission projects from the current cost recovery rider to base rates. In July 2010, we filed for an updated billing factor that includes additional transmission projects and expenses, including the CapX2020 projects, which we expect to be approved in early 2011.

Environmental Matters.

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

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

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.

Air. The electric utility industry is heavily regulated both at the Federal and State level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of Minnesota Power’s generating facilities are equipped with pollution control equipment such as scrubbers, bag houses, and low NOx technologies. At this time, these facilities are substantially compliant 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. 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 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 2006, 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 requirements for that unit. In December 2009, the MPCA approved the SIP for submittal to the EPA for its review and approval. Approval by the EPA is pending on whether to approve the Minnesota SIP. 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 more stringent air emission limitations on sources of air pollutants in the state. Four NAAQS have either recently been revised, or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA is proposing 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 July 2011. As proposed, states have until early 2014 to submit plans outlining how they will meet the standards.

Particulate Matter NAAQS. The EPA finalized the NAAQS Particulate Matter standards in September 2006. The EPA established a more stringent 24-hour average fine particulate (PM2.5) standard and kept 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 ambient 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. As early as late 2014, affected sources would have to take additional control measures if modeling demonstrates non-compliance at the property boundary.

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 also result in more stringent emission limits on our steam generating facilities, possibly resulting in additional control measures on some of our units.

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.

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.

EPA Regulation of GHG Emissions. On May 13, 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The PSD/Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, at existing facilities that undergo major modifications, and at other facilities characterized as major sources under the Clean Air Act’s Title V program.

For our existing facilities, the rule does not require amending our existing Title V Operating Permits to include GHGs requirements. Implementation of the requirement to add GHG provisions to permits 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 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.

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

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

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 sought comments on three general regulatory schemes for coal ash. Public comments were submitted to the EPA by November 19, 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 December 31, 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 December 31, 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, 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 $10.0 million, of which $6.7 million is needed to meet the requirements for BNI Coal’s total reclamation liability currently estimated at $25.1 million. BNI Coal does not believe it is likely that any of these outstanding bonds will be drawn upon.

ALLETE Properties. As of December 31, 2010, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $11.6 million primarily related to performance and maintenance obligations to governmental entities to construct improvements in their 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; 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 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 assessments imposed, levied and collected by each district. The assessments were billed to the landowners 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 December 31, 2010, we owned 69 percent of the assessable land in the Town Center District (69 percent at December 31, 2009) and 93 percent of the assessable land in the Palm Coast Park District (86 percent at December 31, 2009). At these ownership levels our annual assessments are $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. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.

Legal Proceedings. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s, United Taconite, LLC, property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 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 expense related to any damages that may result from the lawsuit has not been recorded as of December 31, 2010, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance coverage for potential loss.

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

Income Tax Expense

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Income Tax Expense

Note 13.

Income Tax Expense

On March 23, 2010, the Patient Protection and Affordable Care Act, 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 2010. On October 8, 2010, we submitted a filing with the MPUC to request deferral of the retail portion of Medicare Part D of this legislation. As we are unable to predict the outcome at this time, we have not deferred any portion of this amount as a regulatory asset.

Income Tax Expense
Year Ended December 31	2010	2009	2008
Millions
Current Tax Expense (Benefit)
Federal (a)	$(23.0)	$(42.6)	$6.2
State	1.3	(1.8)	(1.6)
Total Current Tax Expense (Benefit)	(21.7)	(44.4)	4.6
Deferred Tax Expense
Federal (b)	61.4	66.0	29.3
State	5.3	10.3	13.4
Change in Valuation Allowance	0.2	(0.1)	(2.9)
Investment Tax Credit Amortization	(0.9)	(1.0)	(1.0)
Total Deferred Tax Expense	66.0	75.2	38.8
Total Income Tax Expense	$44.3	$30.8	$43.4

(a)

The 2010 federal current tax benefit is primarily due to the implementation of tax planning initiatives and bonus depreciation provisions in the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 and the Small Business Jobs Act of 2010. The 2009 federal current tax benefit is primarily due to bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009.

(b)

The 2010 federal deferred tax expense is primarily due to tax planning initiatives and bonus depreciation provisions of the Small Business Jobs Act of 2010 and the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010. Also included in 2010 is a one-time charge of $4.0 million as a result of the Patient Protection and Affordable Care Act. The 2009 federal deferred tax expense is primarily due to bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009.

Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2010	2009	2008
Millions
Income Before Non-Controlling Interest and Income Taxes	$119.1	$91.5	$126.4
Statutory Federal Income Tax Rate	35%	35%	35%
Income Taxes Computed at 35 percent Statutory Federal Rate	$41.7	$32.0	$44.2
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	4.5	5.4	4.8
Impact of Patient Protection and Affordable Care Act	4.0	–	–
Regulatory Differences for Utility Plant	(2.0)	(2.5)	(1.6)
Production Tax Credit	(1.6)	(1.2)	(0.4)
Other	(2.3)	(2.9)	(3.6)
Total Income Tax Expense	$44.3	$30.8	$43.4

The effective tax rate on income was 37.2 percent for 2010 (33.7 percent for 2009; 34.3 percent for 2008).

Deferred Tax Assets and Liabilities
As of December 31	2010	2009
Millions
Deferred Tax Assets
Employee Benefits and Compensation (a)	$121.8	$118.2
Property Related	51.1	46.5
NOL and Tax Credit Carryforward	28.2	–
Investment Tax Credits	9.7	10.0
Other	12.7	14.4
Gross Deferred Tax Assets	223.5	189.1
Deferred Tax Asset Valuation Allowance	(0.5)	(0.3)
Total Deferred Tax Assets	$223.0	$188.8
Deferred Tax Liabilities
Property Related	$387.2	$294.1
Regulatory Asset for Benefit Obligations	105.8	96.5
Unamortized Investment Tax Credits	13.7	14.1
Partnership Basis Differences	19.4	14.6
Other	27.3	28.2
Total Deferred Tax Liabilities	$553.4	$447.5
Net Deferred Income Taxes	$330.4	$258.7

Recorded as:
Net Current Deferred Tax Liabilities (b)	$5.2	$5.6
Net Long-Term Deferred Tax Liabilities	325.2	253.1
Net Deferred Income Taxes	$330.4	$258.7

(a)	Includes unfunded employee benefits

(b)	Included in Other Current Liabilities.

NOL and Tax Credit Carryforwards
Year Ended December 31	2010	2009
Millions
Federal NOL carryforward (a)	$62.0	$7.3
Federal tax credit carryforwards	3.7	1.9
State NOL carryforward (a)	71.7	59.6
State tax credit carryforwards, net of federal detriment	1.7	0.1

(a)	Pretax amounts

In 2010 we had federal and state NOLs and tax credit carryforwards primarily due to bonus depreciation provisions in the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 and the Small Business Jobs Act of 2010. The 2010 federal NOL will be partially utilized by carrying it back against prior years’ income with the remainder carried forward to offset future years’ income. We expect to fully utilize the federal NOL and tax credit carryforwards; therefore a deferred tax asset has been recorded to recognize the resulting tax benefit. The state NOL and tax credits will be carried forward to future tax years. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration. The 2009 federal and state NOL were primarily due to bonus depreciation provisions in the American Recovery and Reinvestment Act of 2009. The federal and state carryforward periods expire between 2014 and 2030.

Gross Unrecognized Income Tax Benefits	2010	2009	2008
Millions
Balance at January 1	$9.5	$8.0	$5.3
Additions for Tax Positions Related to the Current Year	–	0.5	0.7
Reductions for Tax Positions Related to the Current Year	(0.2)	–	–
Additions for Tax Positions Related to Prior Years	4.4	1.0	4.5
Reduction for Tax Positions Related to Prior Years	–	–	(2.5)
Settlements	(0.3)	–	–
Lapse of Statute	(1.1)	–	–
Balance as of December 31	$12.3	$9.5	$8.0

The gross unrecognized tax benefits as of December 31, 2010, includes $0.6 million of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate.

As of December 31, 2010, we had $0.7 million ($0.9 million for 2009 and $0.6 million for 2008) of accrued interest related to unrecognized tax benefits included in the consolidated balance sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in the consolidated statement of income. In 2010, we recognized a $0.2 million reduction of interest expense (interest expense of $0.4 million for 2009 and $0.4 million for 2008). There were no penalties recognized for 2010, 2009 or 2008.

We file a consolidated federal income tax return in the United States and state income tax returns in various jurisdictions. ALLETE is currently under examination by the IRS for the tax years 2005 through 2009. ALLETE is no longer subject to federal or state examination for years before 2005.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $4.0 million due to statute expirations and anticipated audit settlements. This amount is primarily due to timing issues.

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Pension and Other Postretirement Benefit Plans

Note 15.

Pension and Other Postretirement Benefit Plans

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In 2010, we made total contributions of $26.5 million ($32.9 million in 2009 of which $12.0 million was contributed in shares of ALLETE common stock). We also have defined contribution pension plans covering substantially all employees. The 2010 plan year employer contributions, which are made through our employee stock ownership plan, totaled $7.2 million ($7.1 million for the 2009 plan year.) (See Note 11. Common Stock and Earnings Per Share and Note 16. Employee Stock and Incentive Plans)

In 2006, amendments were made to the non-union defined benefit pension plan and the RSOP. The non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and closed the plan to new participants. In conjunction with the change, contributions were increased to the RSOP. In 2010, the Minnesota Power unions defined benefit pension plan was amended to close the plan to new participants.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to age 55 with 10 years of service. The postretirement health plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In 2010 $12.8 million was contributed to the VEBAs. In 2009 we contributed $9.3 million to the VEBAs and $0.3 million to the grantor trust.

Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. Estimated defined benefit pension and postretirement health and life contributions for 2011 are expected to be $7.8 million and $12.9 million, respectively. Contributions are based on estimates and assumptions that are subject to change.

Accounting for Defined Benefit Pension and Postretirement Benefit Plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their consolidated balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but that are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit costs recognized annually by our regulated companies are expected to be recovered through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset on our consolidated balance sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit costs associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

Pension Obligation and Funded Status
Year Ended December 31	2010	2009
Millions
Accumulated Benefit Obligation	$485.6	$435.9

Change in Benefit Obligation
Obligation, Beginning of Year	$465.2	$440.4
Service Cost	6.2	5.7
Interest Cost	26.2	26.2
Actuarial Loss	47.1	14.6
Benefits Paid	(27.2)	(25.5)
Participant Contributions	8.1	3.9
Obligation, End of Year	$525.6	$465.3
Change in Plan Assets
Fair Value, Beginning of Year	$327.6	$273.7
Actual Return on Plan Assets	45.6	41.6
Employer Contribution	36.0	37.8
Benefits Paid	(27.2)	(25.5)
Fair Value, End of Year	$382.0	$327.6
Funded Status, End of Year	$(143.6)	$(137.7)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.9)	$(0.9)
Noncurrent Liabilities	$(142.8)	$(136.8)

The pension costs that are reported as a component within our consolidated balance sheet, reflected in regulatory long-term assets and accumulated other comprehensive income, consist of the following:

Unrecognized Pension Costs
Year Ended December 31	2010	2009
Millions
Net Loss	$225.1	$196.5
Prior Service Cost	1.4	1.8
Total Unrecognized Pension Costs	$226.5	$198.3

Components of Net Periodic Pension Expense
Year Ended December 31	2010	2009	2008
Millions
Service Cost	$6.2	$5.7	$5.8
Interest Cost	26.2	26.2	25.4
Expected Return on Plan Assets	(33.7)	(33.8)	(32.5)
Amortization of Loss	6.6	3.4	1.6
Amortization of Prior Service Costs	0.5	0.6	0.6
Net Pension Expense	$5.8	$2.1	$0.9

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2010	2009
Millions
Net Loss	$35.2	$6.8
Amortization of Prior Service Costs	(0.5)	(0.6)
Amortization of Gain	(6.6)	(3.4)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$28.1	$2.8

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31	2010	2009
Millions
Projected Benefit Obligation	$525.6	$465.3
Accumulated Benefit Obligation	$485.6	$435.9
Fair Value of Plan Assets	$382.0	$327.6

Postretirement Health and Life Obligation and Funded Status
Year Ended December 31	2010	2009
Millions
Change in Benefit Obligation
Obligation, Beginning of Year	$192.1	$166.9
Service Cost	4.8	4.1
Interest Cost	10.9	10.0
Actuarial Loss	17.6	18.4
Participant Contributions	2.1	1.7
Plan Amendments	(14.2)	(1.3)
Benefits Paid	(9.2)	(7.7)
Obligation, End of Year	$204.1	$192.1
Change in Plan Assets
Fair Value, Beginning of Year	$96.4	$78.6
Actual Return on Plan Assets	12.0	13.9
Employer Contribution	13.4	9.9
Participant Contributions	2.0	1.6
Benefits Paid	(9.1)	(7.6)
Fair Value, End of Year	$114.7	$96.4
Funded Status, End of Year	$(89.4)	$(95.7)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(0.8)	$(0.8)
Noncurrent Liabilities	$(88.6)	$(94.8)

According to the accounting standards for Retirement Benefits only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $19.8 million in irrevocable grantor trusts included in Other Investments on our consolidated balance sheet at December 31, 2010 ($18.2 million at December 31, 2009).

The postretirement health and life costs that are reported as a component within our consolidated balance sheet, reflected in regulatory long-term assets and accumulated other comprehensive income, consist of the following:

Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2010	2009
Millions
Net Loss	$80.1	$69.6
Prior Service Cost	(11.2)	(1.3)
Transition Obligation	0.2	6.9
Total Unrecognized Postretirement Health and Life Costs	$69.1	$75.2

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2010	2009	2008
Millions
Service Cost	$4.8	$4.1	$4.0
Interest Cost	10.9	10.0	9.4
Expected Return on Plan Assets	(9.5)	(8.3)	(7.2)
Amortization of Prior Service Cost	(0.1)	–	–
Amortization of Loss	4.8	2.5	1.4
Amortization of Transition Obligation	2.5	2.5	2.5
Net Postretirement Health and Life Expense	$13.4	$10.8	$10.1

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2010	2009
Millions
Net Loss	$15.3	$12.9
Prior Service Cost (Credit) Arising During the Period	(14.2)	(1.3)
Amortization of Prior Service Cost	0.1	–
Amortization of Transition Obligation	(2.5)	(2.5)
Amortization of Loss	(4.8)	(2.5)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(6.1)	$6.6

Estimated Future Benefit Payments
		Postretirement
	Pension	Health and Life
Millions
2011	$27.5	$8.5
2012	$28.4	$9.5
2013	$29.4	$10.5
2014	$30.6	$11.6
2015	$31.8	$12.7
Years 2016 – 2020	$174.6	$73.3

The pension and postretirement health and life costs recorded in other long-term assets and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2011, are as follows:

		Postretirement
	Pension	Health and Life
Millions
Net Loss	$0.3	$8.5
Prior Service Costs	$12.1	$(1.7)
Transition Obligations	–	$0.1
Total Pension and Postretirement Health and Life Costs	$12.4	$6.9

Weighted-Average Assumptions Used to Determine Benefit Obligation
Year Ended December 31	2010	2009
Discount Rate
Pension	5.36%	5.81%
Postretirement Health and Life	5.40%	5.81%
Rate of Compensation Increase	4.3 – 4.6%	4.3 – 4.6%
Health Care Trend Rates
Trend Rate	10%	8.5%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2018	2017

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2010	2009	2008
Discount Rate	5.81%	6.12%	6.25%
Expected Long-Term Return on Plan Assets
Pension	8.5%	8.5%	9.0%
Postretirement Health and Life	6.8 – 8.5%	6.8 – 8.5%	7.2 – 9.0%
Rate of Compensation Increase	4.3 – 4.6%	4.3 – 4.6%	4.3 – 4.6%

In establishing the expected long-term return on plan assets, we take into account the actual long-term historical performance of our plan assets, the actual long-term historical performance for the type of securities we are invested in, and apply the historical performance utilizing the target allocation of our plan assets to forecast an expected long-term return. Our expected rate of return is then selected after considering the results of each of those factors, in addition to considering the impact of current economic conditions, if applicable, on long-term historical returns.

The discount rate is computed using a yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation.

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent	One Percent
	Increase	Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost	$2.5	$(2.0)
Effect on Postretirement Health and Life Obligation	$23.1	$(19.2)

Actual Plan Asset Allocations
	Pension		Postretirement Health and Life (a)
	2010	2009	2010	2009
Equity Securities	52%	53%	58%	54%
Debt Securities	29%	28%	33%	38%
Real Estate	5%	5%	–	–
Private Equity	14%	14%	9%	8%
	100%	100%	100%	100%

(a)	Includes VEBAs and irrevocable grantor trusts.

Pension plan equity securities did not include any ALLETE common stock at December 31, 2010. At December 31, 2009, $9.9 million, or 3.0 percent, of ALLETE common stock was included.

To achieve strong returns within managed risk, we diversify our asset portfolio to approximate the target allocations in the table below. Equity securities are diversified among domestic companies with large, mid and small market capitalizations, as well as investments in international companies. The majority of debt securities are made up of investment grade bonds.

Plan Asset Target Allocations
		Postretirement
	Pension	Health and Life (a)
Equity Securities	50%	48%
Debt Securities	30%	34%
Real Estate	10%	9%
Private Equity	10%	9%
	100%	100%

(a)	Includes VEBAs and irrevocable grantor trusts.

Level 1 — Quoted prices are available in active markets for identical assets as of the reported date. Active markets are those in which transactions for the asset occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value.

Pension Fair Value

	At Fair Value as of December 31, 2010
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities
U.S. Large-cap (a)	$30.4	$29.9	$3.5	$63.8
U.S. Mid-cap Growth (a)	14.0	13.7	1.6	29.3
U.S. Small-cap (a)	13.7	13.5	1.6	28.8
International	–	77.1	–	77.1
Debt Securities:
Mutual Funds	46.5		–	46.5
Fixed Income	–	65.7	–	65.7
Other Types of Investments:
Private Equity Funds	–	–	50.7	50.7
Real Estate	–	–	20.1	20.1
Total Fair Value of Assets	$104.6	$199.9	$77.5	$382.0

	Equity Securities
Activity in Level 3	(Auction Rate Securities)	Private Equity Funds	Real Estate
Millions
Balance as of December 31, 2009	$9.1	$44.7	$17.3
Actual Return on Plan Assets	–	(4.1)	(6.1)
Purchases, sales, and settlements, net	(2.4)	10.1	8.9
Balance as of December 31, 2010	$6.7	$50.7	$20.1

	At Fair Value as of December 31, 2009
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities
U.S. Large-cap (a)	$23.2	$27.5	$5.2	$55.9
U.S. Mid-cap Growth (a)	8.9	10.6	2.0	21.5
U.S. Small-cap (a)	8.6	10.1	1.9	20.6
International	–	66.4	–	66.4
ALLETE	9.9	–	–	9.9
Debt Securities:
Mutual Funds	32.0	–	–	32.0
Fixed Income	–	59.3	–	59.3
Other Types of Investments:
Private Equity Funds	–	–	44.7	44.7
Real Estate	–	–	17.3	17.3
Total Fair Value of Assets	$82.6	$173.9	$71.1	$327.6

(a)

The underlying investments classified under U.S. Equity Securities consist of Money Market Funds and U.S. Government Bonds (Level 1), Hedge Funds (Level 2), and Auction Rate Securities (Level 3), which are combined with futures, which settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.

Recurring Fair Value Measures	Equity Securities
Activity in Level 3	(Auction Rate Securities)	Private Equity Funds	Real Estate
Millions
Balance as of December 31, 2008	$10.2	$43.2	$17.0
Actual Return on Plan Assets	0.1	(8.7)	(8.6)
Purchases, sales, and settlements, net	(1.1)	10.2	8.9
Balance as of December 31, 2009	$9.1	$44.7	$17.3

Postretirement Health and Life Fair Value

	At Fair Value as of December 31, 2010
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities
U.S. Large-cap	$15.7	–	–	$15.7
U.S. Mid-cap Growth	11.4	–	–	11.4
U.S. Small-cap	11.5	–	–	11.5
International	26.8	–	–	26.8
Debt Securities:
Mutual Funds	9.0	–	–	9.0
Fixed Income	–	$27.9	–	27.9
Other Types of Investments:
Private Equity Funds	–	–	$12.4	12.4
Total Fair Value of Assets	$74.4	$27.9	$12.4	$114.7

Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2009	$9.4
Actual Return on Plan Assets	1.4
Purchases, sales, and settlements, net	1.6
Balance as of December 31, 2010	$12.4

	At Fair Value as of December 31, 2009
Recurring Fair Value Measures	Level 1	Level 2	Level 3	Total
Millions
Assets:
Equity Securities
U.S. Large-cap	$13.4	–	–	$13.4
U.S. Mid-cap Growth	9.0	–	–	9.0
U.S. Small-cap	6.3	–	–	6.3
International	21.4	–	–	21.4
Debt Securities:
Mutual Funds	5.5	–	–	5.5
Fixed Income	–	$31.4	–	31.4
Other Types of Investments:
Private Equity Funds	–	–	$9.4	9.4
Total Fair Value of Assets	$55.6	$31.4	$9.4	$96.4

Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2008	$7.9
Actual Return on Plan Assets	(1.1)
Purchases, sales, and settlements, net	2.6
Balance as of December 31, 2009	$9.4

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provides guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide postretirement health benefits that include prescription drug benefits, which qualify us for the federal subsidy under the Act.

- Definition

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

+ References

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-Name Accounting Principles Board Opinion (APB)

-Number 30

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-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

+ Details

Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2010

Notes to Financial Statements [Abstract]

Employee Stock and Incentive Plans

Note 16.

Employee Stock and Incentive Plans

Employee Stock Ownership Plan. We sponsor a leveraged ESOP within the RSOP. As of their date of hire, eligible employees may to contribute to the RSOP plan. In 1990, the ESOP issued a $75 million note (term not to exceed 25 years at 10.25 percent) to us as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent. We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for its debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest. ESOP compensation expense was $7.1 million in 2010 ($6.5 million in 2009; $10.1 million in 2008).

According to the accounting standards for stock compensation, unallocated ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered as outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

Year Ended December 31	2010	2009	2008
Millions
ESOP Shares
Allocated	2.2	2.2	2.0
Unallocated	1.3	1.5	1.9
Total	3.5	3.7	3.9
Fair Value of Unallocated Shares	$48.4	$49.0	$61.3

Stock-Based Compensation. Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, stock appreciation rights and other awards. There are 1.4 million shares of common stock reserved for issuance under the Executive Plan, with 0.7 million of these shares available for issuance as of December 31, 2010.

We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired on January 1, 2006. No grants have been made since 2003 under the Director Plan. Approximately 2,586 options were outstanding under the Director Plan at December 31, 2010.

We currently have the following types of share-based awards outstanding:

Non-Qualified Stock Options. The options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are cancelled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is retirement eligible.

No stock options were granted under our Executive Long-Term Incentive Compensation Plan in 2009 or 2010. The following assumptions were used in determining the fair value of stock options granted during 2008, under the Black-Scholes option-pricing model:

	2008
Risk-Free Interest Rate	2.8%
Expected Life	5 Years
Expected Volatility	20%
Dividend Growth Rate	4.4%

The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the grant date. Expected volatility is estimated based on the historic volatility of our stock and the stock of our peer group companies. We utilize historical option exercise and employee pre-vesting termination data to estimate the option life. The dividend growth rate is based upon historical growth rates in our dividends.

Performance Shares. Under the performance share awards plan, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies. In the case of qualified retirement, death or disability during a performance period, a pro-rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro-rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined by the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

Restricted Stock Units. Under the restricted stock units plan, shares vest monthly over a three year period. In the case of qualified retirement, death or disability, a pro-rata portion of the award will be earned. In the case of termination of employment for any other reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro-rata portion of the award will be paid. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.

Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards.

RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.

The following share-based compensation expense amounts were recognized in our consolidated statement of income for the periods presented.

Share-Based Compensation Expense
Year Ended December 31	2010	2009	2008
Millions
Stock Options	$0.1	$0.3	$0.7
Performance Shares	1.5	1.5	1.1
Restricted Stock Units	0.6	0.3	–
Total Share-Based Compensation Expense	$2.2	$2.1	$1.8
Income Tax Benefit	$0.9	$0.8	$0.7

There were no capitalized stock-based compensation costs at December 31, 2010, 2009, or 2008.

As of December 31, 2010, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our consolidated statements of income was $1.5 million and $0.7 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.6 years for both performance share awards and restricted stock units.

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2010.

	2010		2009		2008
		Weighted-Average		Weighted-Average		Weighted-Average
	Number of	Exercise	Number of	Exercise	Number of	Exercise
	Options	Price	Options	Price	Options	Price

Outstanding as of January 1,	646,235	$40.05	672,419	$39.99	510,992	$39.83
Granted (a)	–	–	–	–	180,815	$39.10
Exercised	40,769	$27.76	4,508	$18.85	16,627	$25.56
Forfeited	44,579	$43.16	21,676	$42.62	2,761	$39.39
Outstanding as of December 31,	560,887	$40.69	646,235	$40.05	672,419	$39.99
Exercisable as of December 31,	523,491	$39.76	512,743	$37.34	406,894	$34.48

(a)	Stock options have not been granted since 2008.

Cash received from non-qualified stock options exercised was $1.1 million in 2010. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18 for 2008 (none in 2010 or 2009). The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.3 million during 2010 ($0.1 million in 2009; $0.2 million in 2008).

	Range of Exercise Price
As of December 31, 2010	$18.85 to $29.79	$37.76 to $41.35	$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	44,738	296,770	181,983
Weighted Average Remaining Contractual Life (Years)	1.5	5.4	5.5
Weighted Average Exercise Price	$26.96	$39.44	$46.37

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2010.

	2010		2009		2008
		Weighted-		Weighted-		Weighted-
		Average		Average		Average
	Number of	Grant Date	Number of	Grant Date	Number of	Grant Date
	Shares	Fair Value	Shares	Fair Value	Shares	Fair Value
Non-vested as of January 1,	121,825	$41.96	79,238	$47.94	68,501	$45.63
Granted	49,302	$35.44	69,800	$35.06	36,684	$54.05
Unearned Grant Award	(22,909)	$54.50	(24,615)	$41.97	(23,624)	$42.80
Forfeited	(25,729)	$36.45	(2,598)	$38.78	(2,323)	$50.87
Non-vested as of December 31,	122,489	$38.15	121,825	$41.96	79,238	$47.94

Less than 0.1 million performance share were granted in February 2010 for the performance period ending in 2012. The ultimate issuance is contingent upon the attainment of certain future market goals of ALLETE during the performance periods. The grant date fair value of the performance share awards was $1.2 million.

No performance shares were awarded in February 2010 for the three year performance period ending in 2009, as performance targets were not met. However, in accordance with the accounting standards for stock compensation, no compensation expense previously recognized in connection with those grants will be reversed.

Less than 0.1 million performance shares were awarded in February 2011 for the three year performance period ending in 2010. The grant date fair value of the shares awarded was $1.6 million.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2010.

	2010		2009
		Weighted- Average		Weighted- Average
	Number of	Grant Date	Number of	Grant Date
	Shares	Fair Value	Shares	Fair Value
Available as of January 1,	28,983	$29.41	–	–
Granted	26,589	$31.83	30,465	$29.41
Awarded	(3,091)	$29.75	–	–
Forfeited	(8,678)	$30.62	(1,482)	$29.41
Available as of December 31,	43,803	$30.61	28,983	$29.41

Less than 0.1 million restricted stock units were granted in February 2010 for the vesting period ending in 2012. The grant date fair value of the restricted stock unit awards was $0.7 million.

Less than 0.05 million restricted stock units were awarded in 2010. The grant date fair value of the shares awarded was $0.1 million.

Entity Information (USD $)	12 Months Ended
Entity Information (USD $)	Dec. 31, 2010	Feb. 01, 2011	Jun. 30, 2010
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,214,198,439
Entity Common Stock, Shares Outstanding		35,820,559
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	FY

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

Document Information	12 Months Ended
Document Information	Dec. 31, 2010
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2010