Document and Entity Information Document (USD $)	12 Months Ended
Document and Entity Information Document (USD $)	Dec. 31, 2013	Feb. 01, 2014	Jun. 30, 2013
Document Information [Line Items]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,989,608,714
Entity Common Stock, Shares Outstanding		41,817,714
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets
Cash and Cash Equivalents	$ 97.3	$ 80.8
Accounts Receivable (Less Allowance of $1.1 and $1.0)	96.3	89.0
Inventories	59.3	69.8
Prepayments and Other	35.1	33.6
Deferred Income Taxes	19.0	0
Total Current Assets	307.0	273.2
Property, Plant and Equipment - Net	2,576.5	2,347.6
Regulatory Assets	263.8	340.3
Investment in ATC	114.6	107.3
Other Investments	146.3	143.5
Other Non-Current Assets	68.6	41.5
Total Assets	3,476.8	3,253.4
Current Liabilities
Accounts Payable	99.9	90.5
Accrued Taxes	34.8	30.2
Accrued Interest	15.7	15.6
Long-Term Debt Due Within One Year	27.2	84.5
Other	52.6	62.6
Total Current Liabilities	230.2	283.4
Long-Term Debt	1,083.0	933.6
Deferred Income Taxes	479.1	423.8
Regulatory Liabilities	81.0	60.1
Defined Benefit Pension and Other Postretirement Benefit Plans	133.4	228.2
Other Non-Current Liabilities	127.2	123.3
Total Liabilities	2,133.9	2,052.4
Commitments and Contingencies (Note 12)
Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 41.4 and 39.4 Shares Outstanding	885.2	784.7
Unearned ESOP Shares	(14.3)	(21.3)
Accumulated Other Comprehensive Loss	(17.1)	(22.0)
Retained Earnings	489.1	459.6
Total Equity	1,342.9	1,201.0
Total Liabilities and Equity	$ 3,476.8	$ 3,253.4

Consolidated Balance Sheet Parentheticals (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.1	$ 1.0
Common Stock [Abstract]
Common Stock, Par Value	$ 0	$ 0
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	41.4	39.4

Consilidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenue	$ 1,018.4	$ 961.2	$ 928.2
Operating Expenses
Fuel and Purchased Power	334.8	308.7	306.6
Operating and Maintenance	412.9	397.1	381.2
Depreciation	116.6	100.2	90.4
Total Operating Expenses	864.3	806.0	778.2
Operating Income	154.1	155.2	150.0
Other Income (Expense)
Interest Expense	(50.3)	(45.5)	(43.6)
Equity Earnings in ATC	20.3	19.4	18.4
Other	9.3	6.0	4.4
Total Other Expense	(20.7)	(20.1)	(20.8)
Income Before Non-Controlling Interest and Income Taxes	133.4	135.1	129.2
Income Tax Expense	28.7	38.0	35.6
Net Income	104.7	97.1	93.6
Less: Non-Controlling Interest in Subsidiaries	0	0	(0.2)
Net Income Attributable to ALLETE	$ 104.7	$ 97.1	$ 93.8
Average Shares of Common Stock
Basic (in shares)	39.7	37.6	35.3
Diluted (in shares)	39.8	37.6	35.4
Basic Earnings Per Share of Common Stock	$ 2.64	$ 2.59	$ 2.66
Diluted Earnings Per Share of Common Stock	$ 2.63	$ 2.58	$ 2.65
Dividends Per Share of Common Stock	$ 1.90	$ 1.84	$ 1.78

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Income	$ 104.7	$ 97.1	$ 93.6
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities -Net of Income Taxes of $–, $0.8 and $(0.1)	0	1.2	(0.3)
Unrealized Gain (Loss) on Derivatives - Net of Income Taxes of $–, $(0.1) and $(0.2)	0.1	(0.2)	(0.3)
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Taxes of $3.3, $3.9 and $(3.6)	4.8	5.9	(5.1)
Total Other Comprehensive Income (Loss)	4.9	6.9	(5.7)
Total Comprehensive Income	109.6	104.0	87.9
Less: Non-Controlling Interest in Subsidiaries	0	0	(0.2)
Comprehensive Income Attributable to ALLETE	$ 109.6	$ 104.0	$ 88.1

- Definition

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

+ References+ Details

Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain (Loss) on Securities, Taxes	$ 0	$ 0.8	$ (0.1)
Unrealized Loss on Derivatives, Taxes	0	(0.1)	(0.2)
Defined Benefit Pension and Other Postretirement Benefit Plans, Taxes	$ 3.3	$ 3.9	$ (3.6)

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities
Net Income	$ 104.7	$ 97.1	$ 93.6
Allowance for Funds Used During Construction - Equity	(4.6)	(5.1)	(2.5)
Income from Equity Investments, Net of Dividends	(4.2)	(3.7)	(3.2)
Gain on Real Estate Foreclosure	0	0	(0.5)
Loss (Gain) on Sale of Assets	(0.4)	0.2	(0.9)
Gain on Sale of Investments	(2.2)	0	0
Loss on Impairment of Assets	0	0	1.7
Depreciation Expense	116.6	100.2	90.4
Amortization of Debt Issuance Costs	1.0	1.0	0.9
Deferred Income Tax Expense (Benefit)	28.6	37.5	35.8
Share-Based Compensation Expense	2.4	2.1	1.6
ESOP Compensation Expense	8.4	7.7	7.4
Defined Benefit Pension and Other Postretirement Benefit Expense	21.0	27.5	23.6
Bad Debt Expense	1.3	1.0	1.2
Changes in Operating Assets and Liabilities
Accounts Receivable	(8.6)	(10.1)	18.6
Inventories	10.5	(0.7)	(9.1)
Prepayments and Other	(1.4)	(6.5)	1.5
Accounts Payable	1.1	(1.5)	(9.5)
Other Current Liabilities	1.4	21.8	15.4
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans	(10.8)	(8.8)	(24.7)
Changes in Regulatory and Other Non-Current Assets	(18.3)	(20.9)	(7.5)
Changes in Regulatory and Other Non-Current Liabilities	(7.1)	0.8	7.9
Cash from Operating Activities	239.4	239.6	241.7
Investing Activities
Proceeds from Sale of Available-for-sale Securities	16.1	1.5	7.8
Payments for Purchase of Available-for-sale Securities	(4.7)	(1.8)	(2.3)
Investment in ATC	(3.1)	(4.7)	(2.0)
Changes to Other Investments	(12.3)	(9.6)	(7.4)
Additions to Property, Plant and Equipment	(328.5)	(405.8)	(239.2)
Changes to Restricted Cash	(5.4)	0	0
Proceeds from Sale of Assets	1.3	0.3	2.2
Cash for Investing Activities	(336.6)	(420.1)	(240.9)
Financing Activities
Proceeds from Issuance of Common Stock	98.2	77.0	39.1
Proceeds from Issuance of Long-Term Debt	169.8	180.6	81.4
Changes in Notes Payable	0	(1.1)	0.1
Reductions of Long-Term Debt	(77.7)	(25.9)	(3.1)
Debt Issuance Costs	(1.4)	(1.3)	0
Dividends on Common Stock	(75.2)	(69.1)	(62.1)
Cash from Financing Activities	113.7	160.2	55.4
Change in Cash and Cash Equivalents	16.5	(20.3)	56.2
Cash and Cash Equivalents at Beginning of Period	80.8	101.1	44.9
Cash and Cash Equivalents at End of Period	$ 97.3	$ 80.8	$ 101.1

Consolidated Statement of Shareholders' Equity (USD $) In Millions, unless otherwise specified	Total	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Unearned ESOP Shares	Common Stock
Balance at Dec. 31, 2010	$ 976.0	$ 399.9	$ (23.2)	$ (36.8)	$ 636.1
Comprehensive Income
Net Income	93.6	93.6
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	(0.3)		(0.3)
Unrealized Gain (Loss) on Derivatives - Net	(0.3)		(0.3)
Defined Benefit Pension and Other Postretirement Plans - Net	(5.1)		(5.1)
Total Comprehensive Income	87.9
Non-Controlling Interest in Subsidiaries	0.2	0.2
Comprehensive Income Attributable to ALLETE	88.1
Common Stock Issued - Net	69.5				69.5
Dividends Declared	(62.1)	(62.1)
ESOP Shares Earned	7.8			7.8
Balance at Dec. 31, 2011	1,079.3	431.6	(28.9)	(29.0)	705.6
Comprehensive Income
Net Income	97.1	97.1
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	1.2		1.2
Unrealized Gain (Loss) on Derivatives - Net	(0.2)		(0.2)
Defined Benefit Pension and Other Postretirement Plans - Net	5.9		5.9
Total Comprehensive Income	104.0
Non-Controlling Interest in Subsidiaries	0
Comprehensive Income Attributable to ALLETE	104.0
Common Stock Issued - Net	79.1				79.1
Dividends Declared	(69.1)	(69.1)
ESOP Shares Earned	7.7			7.7
Balance at Dec. 31, 2012	1,201.0	459.6	(22.0)	(21.3)	784.7
Comprehensive Income
Net Income	104.7	104.7
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Derivatives - Net	0.1		0.1
Defined Benefit Pension and Other Postretirement Plans - Net	4.8		4.8
Total Comprehensive Income	109.6
Non-Controlling Interest in Subsidiaries	0
Comprehensive Income Attributable to ALLETE	109.6
Common Stock Issued - Net	100.5				100.5
Dividends Declared	(75.2)	(75.2)
ESOP Shares Earned	7.0			7.0
Balance at Dec. 31, 2013	$ 1,342.9	$ 489.1	$ (17.1)	$ (14.3)	$ 885.2

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Operations and Significant Accounting Policies [Abstract]

Operations and Significant Accounting Policies [Text Block]

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 our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 143,000 retail customers. In 2013, Minnesota Power’s non-affiliated municipal customers consisted of 16 municipalities in Minnesota and 1 Wisconsin utility which terminated its contract effective December 31, 2013. SWL&P is also a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 5,000 acres of land 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 2013, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under a long-term contract. (See Note 12. 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 represents 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, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. ALLETE does not intend to acquire additional Florida real estate.

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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, and are 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 sold 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 are recorded and the related assets are adjusted to their estimated fair value. (See Note 8. Investments.)

ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE, operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements, and will be subject to applicable state and federal regulatory jurisdiction.

Non-Controlling Interest in Subsidiaries. In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at book value for $8.8 million by issuing 0.2 million shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or comprehensive income.

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
Year Ended December 31	2013		2012		2011
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$47.5		$42.7		$43.2
Cash Paid (Received) During the Period for Income Taxes (a)		$0.5	—		$(11.4)
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$8.3		$20.2	$5.9
Increase (Decrease) in Capitalized Asset Retirement Costs	$(0.7)			$17.1		$0.3
AFUDC – Equity		$4.6		$5.1		$2.5
ALLETE Common Stock Contributed to the Pension Plan	—		—		$(20.0)


(a)	Due to bonus depreciation provisions in 2010 and 2012 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and in 2011, refunds were received from NOL carrybacks against prior years’ taxable income.

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	2013		2012
Millions
Trade Accounts Receivable
Billed		$78.7		$70.4
Unbilled	18.7		17.4
Less: Allowance for Doubtful Accounts	1.1		1.0
Total Trade Accounts Receivable	96.3		86.8
Income Taxes Receivable	—		2.2
Total Accounts Receivable - Net		$96.3		$89.0

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Concentration of Credit Risk. Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to 9 Large Power Customers. Receivables from these customers totaled $14.2 million at December 31, 2013 ($13.7 million at December 31, 2012). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power’s taconite-producing Large Power Customers are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 12.0 percent of consolidated revenue in 2013 (12.3 percent in 2012; 12.6 percent in 2011).

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 receivables 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 8. 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 8. 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	2013		2012
Millions
Fuel (a)		$13.1		$28.0
Materials and Supplies	46.2		41.8
Total Inventories		$59.3		$69.8


(a)	Fuel inventory was lower in 2013 primarily due to higher than expected thermal generation and the timing of coal shipments.

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. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 3. Property, Plant and Equipment.)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed for the recovery of the remaining book value of retired plant assets. In January 2013, we announced the retirement of Taconite Harbor Unit 3 and conversion of Laskin Energy Center to natural gas in 2015, which were included in our 2013 Integrated Resource Plan approved by the MPUC in an order dated November 12, 2013. Accordingly, we do not expect any impairment charge as a result of the retirement of Taconite Harbor Unit 3 or conversion of the Laskin Energy Center.

Impairment of Long-Lived Assets. Land inventory is accounted for as held for use and is recorded at cost. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, may vary among each land parcel or bulk sale, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.

In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. Our undiscounted future net cash flow analysis was estimated using management’s current intent for disposition of each property, which is an estimated selling period of five to ten years based on a December 2013 asset management and disposition plan (Plan) which will be reviewed annually for adjustment or modification. Future selling prices have been estimated through management’s best estimate of future sales prices in collaboration and consultation with outside advisors, and based on the best use of the properties over the expected period of sale. The undiscounted future net cash flow analysis assumes two scenarios: retail land sales followed by project bulk sales over a five-year period and retail land sales over a ten-year period. Our analysis assumes the most likely case of retail land sales followed by project bulk sales over a five-year period; however, under both scenarios, except as noted below, the undiscounted future net cash flows exceeded carrying values. If our major development projects are sold in one bulk sale or if the properties are sold differently than anticipated in the Plan, the actual results could be materially different from our undiscounted future net cash flow analysis.

The results of the impairment analysis are particularly dependent on the estimated future sales prices, method of disposition, and holding period for each property. The estimated holding period, as set forth in the Plan, is based on management’s current intent for the use and disposition of each property, and is subject to change in future periods if the intentions of the Company were to change.

In the event that projected undiscounted future net cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset’s fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value of the asset is less than its carrying value, its carrying value is reduced and an impairment charge is recorded in the current period. In 2013, impairment analyses of estimated undiscounted future net cash flows were conducted and indicated that the cash flows were adequate to recover the carrying value of our land inventory. As a result, there was no impairment recorded for the year ended December 31, 2013 (none for the year ended December 31, 2012, $1.7 million for the year ended December 31, 2011).

Other Non-Current Assets. As of December 31, 2013, included in other non-current assets on the Consolidated Balance Sheet was restricted cash of $5.4 million related to cash held in escrow pending closing of the acquisition of wind energy facilities by ALLETE Clean Energy, which occurred on January 30, 2014. (See Note 7. Acquisitions.)

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings. (See Note 9. Derivatives.)

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 18. Employee Stock and Incentive Plans.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Prepayments and Other Current Assets
As of December 31	2013		2012
Millions
Deferred Fuel Adjustment Clause		$23.0		$22.5
Other	12.1		11.1
Total Prepayments and Other Current Assets		$35.1		$33.6



Other Current Liabilities
As of December 31	2013		2012
Millions
Customer Deposits		$26.0		$28.8
Other	26.6		33.8
Total Other Current Liabilities		$52.6		$62.6



Other Non-Current Liabilities
As of December 31	2013		2012
Millions
Asset Retirement Obligation		$81.8		$77.9
Other	45.4		45.4
Total Other Non-Current Liabilities		$127.2		$123.3

Environmental Liabilities. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers. (See Note 12. 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 yet 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 transmission, renewable energy and environmental 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. BNI Coal recognizes revenue when coal is delivered.

We account for revenue from our cost recovery riders (renewable resources, transmission and environmental improvement) in accordance with the accounting standards for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows automatic adjustment of future rates, the amount of the revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. Revenue recognized using the alternative revenue program guidance is included in operating revenue on our Consolidated Statement of Income and regulatory assets on our Consolidated Balance Sheet until it is subsequently collected from customers.

Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 which approximates the effective interest method.

Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return and combined and separate state income tax returns. 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 15. 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.

New Accounting Standards.

Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued an accounting standard update on disclosure of amounts reclassified out of accumulated other comprehensive income. This update requires entities to provide information about amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This guidance, which was adopted beginning with the quarter ended March 31, 2013, and required additional disclosures, did not have an impact on our consolidated financial position, results of operations, or cash flows. (See Note 16. Reclassifications Out of Accumulated Other Comprehensive Income (Loss).)

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

Business Segments

12 Months Ended

Dec. 31, 2013

Business Segments [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.



	Consolidated			Regulated Operations			Investments and Other
Millions
2013
Operating Revenue		$1,018.4			$925.5			$92.9
Fuel and Purchased Power Expense	334.8			334.8			—
Operating and Maintenance Expense	412.9			322.4			90.5
Depreciation Expense	116.6			110.2			6.4
Operating Income (Loss)	154.1			158.1			(4.0		)
Interest Expense	(50.3		)	(42.1		)	(8.2		)
Equity Earnings in ATC	20.3			20.3			—
Other Income	9.3			4.7			4.6
Income (Loss) Before Income Taxes	133.4			141.0			(7.6		)
Income Tax Expense (Benefit)	28.7			36.1			(7.4		)
Net Income (Loss)		$104.7			$104.9		$(0.2)
Total Assets		$3,476.8			$3,160.8			$316.0
Capital Additions		$339.5			$326.3			$13.2



	Consolidated			Regulated Operations			Investments and Other
Millions
2012
Operating Revenue		$961.2			$874.4			$86.8
Fuel and Purchased Power Expense	308.7			308.7			—
Operating and Maintenance Expense	397.1			310.0			87.1
Depreciation Expense	100.2			93.9			6.3
Operating Income (Loss)	155.2			161.8			(6.6		)
Interest Expense	(45.5		)	(39.8		)	(5.7		)
Equity Earnings in ATC	19.4			19.4			—
Other Income	6.0			5.1			0.9
Income (Loss) Before Income Taxes	135.1			146.5			(11.4		)
Income Tax Expense (Benefit)	38.0			50.4			(12.4		)
Net Income		$97.1			$96.1			$1.0
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
2011
Operating Revenue		$928.2			$851.9			$76.3
Fuel and Purchased Power Expense	306.6			306.6			—
Operating and Maintenance Expense	381.2			301.5			79.7
Depreciation Expense	90.4			85.4			5.0
Operating Income (Loss)	150.0			158.4			(8.4		)
Interest Expense	(43.6		)	(35.8		)	(7.8		)
Equity Earnings in ATC	18.4			18.4			—
Other Income	4.4			2.6			1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	129.2			143.6			(14.4		)
Income Tax Expense (Benefit)	35.6			43.2			(7.6		)
Net Income (Loss)	93.6			100.4			(6.8		)
Less: Non-Controlling Interest in Subsidiaries	(0.2		)	—			(0.2		)
Net Income (Loss) Attributable to ALLETE		$93.8			$100.4		$(6.6)
Total Assets		$2,876.0			$2,579.8			$296.2
Capital Additions		$246.8			$228.0			$18.8

- Definition

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

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+ Details

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2013			2012
Millions
Regulated Utility		$3,380.0			$3,232.9
Construction Work in Progress	303.9			151.8
Accumulated Depreciation	(1,181.7		)	(1,102.8		)
Regulated Utility Plant - Net	2,502.2			2,281.9
Non-Rate Base Energy Operations	131.3			118.0
Construction Work in Progress	3.4			4.2
Accumulated Depreciation	(60.4		)	(56.7		)
Non-Rate Base Energy Operations Plant - Net	74.3			65.5
Other Plant - Net	—			0.2
Property, Plant and Equipment - Net		$2,576.5			$2,347.6

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.



Estimated Useful Lives of Property, Plant and Equipment
Generation	5 to 35 years	Distribution	14 to 65 years
Transmission	42 to 61 years	Other Plant	5 to 25 years

NOTE 3. PROPERTY, PLANT AND EQUIPMENT (Continued)

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction or development and/or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our coal-fired and wind generating facilities and land reclamation at BNI Coal, and are included in other non-current liabilities on our Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.

Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal costs have not been recognized because they are considered immaterial to our consolidated financial statements.

Long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-ARO obligations. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with the guidance for AROs. (See Note 5. Regulatory Matters.)



Asset Retirement Obligation
Millions
Obligation as of December 31, 2011		$57.0
Accretion Expense	3.8
Revisions in estimated cash flows	17.1
Obligation as of December 31, 2012	77.9
Accretion Expense	4.6
Revisions in estimated cash flows	(0.7		)
Obligation as of December 31, 2013		$81.8

- Definition

The entire disclosure for long-lived, physical assets used in the normal conduct of business and not intended for resale. Includes, but is not limited to, accounting policies and methodology, roll forwards, depreciation, depletion and amortization expense, including composite depreciation, accumulated depreciation, depletion and amortization expense, useful lives and method used, income statement disclosures, assets held for sale and public utility disclosures.

+ References+ Details

Jointly-Owned Facilities and Projects

12 Months Ended

Dec. 31, 2013

Jointly-Owned Facilities and Projects [Abstract]

Jointly-Owned Facilities and Projects [Text Block]

JOINTLY-OWNED FACILITIES AND PROJECTS

We own 80 percent of the 585 MW Boswell Unit 4. While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and WPPI Energy, the owner of the remaining 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our Consolidated Statement of Income.

We are a participant in the CapX2020 initiative to ensure reliable electric transmission and distribution in the region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and investor-owned utilities. We are currently participating in three CapX2020 projects with varying ownership percentages.

As of December 31, 2013 our investments in jointly-owned facilities and projects and the related ownership percentages are as follows:



Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
Boswell Unit 4		$416.1		$197.5		$71.5	80
CapX2020 Projects	22.8		1.0		57.7		9.3 - 14.7
Total		$438.9		$198.5		$129.2

Regulatory Matters

12 Months Ended

Dec. 31, 2013

Regulatory Matters [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

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

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

FERC-Approved Wholesale Rates. In 2013, Minnesota Power’s non-affiliated municipal customers consisted of 16 municipalities in Minnesota and 1 Wisconsin utility which terminated its contract effective December 31, 2013. The 17 MW of average monthly demand provided to this wholesale customer is expected to be used to supply power for prospective additional retail and municipal load. SWL&P, a wholly-owned subsidiary of ALLETE, is also a Wisconsin utility and a customer of Minnesota Power. Minnesota Power’s formula-based rate contract with the Nashwauk Public Utilities Commission is effective through June 30, 2024, and the restated formula-based rate contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the Nashwauk Public Utilities Commission contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016.

2012 Wisconsin Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allowed for a 10.9 percent return on common equity.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. On November 12, 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We anticipate filing a petition in the first quarter of 2014 to include additional transmission investments and expenditures in customer billing rates. (See Note 1. Operations and Significant Accounting Policies.)

Renewable Cost Recovery Rider. The Bison Wind Energy Center in North Dakota currently consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in an order dated December 3, 2013.

On September 25, 2013, the NDPSC approved the site permit for construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. As a result, construction has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $55.6 million was spent through December 31, 2013. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We anticipate including Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in the first quarter of 2014, which upon approval, authorizes updated rates to be included on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

Rapids Energy Center. In December 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill. On October 9, 2013, the MPUC issued an order denying, without prejudice, the transfer of assets from non-rate base generation to Minnesota Power’s Regulated Operations. This decision had no impact on the Company’s consolidated financial position, results of operations, or cash flows.

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

NOTE 5. REGULATORY MATTERS (Continued)

Integrated Resource Plan. In an order dated November 12, 2013, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota, installation of emissions control technology at our Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to cleaner-burning natural gas in 2015 and retiring Taconite Harbor Unit 3 in 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $310 million. On November 5, 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. On November 25, 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. On December 20, 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which is expected to be approved in the second quarter of 2014. (See Note 1. Operations and Significant Accounting Policies.)

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 240-mile 500 kV transmission line between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. On October 21, 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined that the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020. (See Note 12. Commitments, Guarantees and Contingencies.)

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

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities represent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable commission or over the corresponding period related to the asset or liability.

NOTE 5. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2013		2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$23.0		$22.5
Total Current Regulatory Assets	23.0		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans (b)	164.1		260.7
Income Taxes	35.3		36.0
Asset Retirement Obligation	16.0		12.1
Cost Recovery Riders (c)	39.6		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.8		3.7
Total Non-Current Regulatory Assets	263.8		340.3

Total Regulatory Assets		$286.8		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.0		$19.5
Plant Removal Obligations	19.7		18.1
Wholesale and Retail Contra AFUDC	19.7		15.5
Defined Benefit Pension and Other Postretirement Plans (b)	16.3		—
Other	8.3		7.0
Total Non-Current Regulatory Liabilities		$81.0		$60.1


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


(b)	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, are recognized as regulatory assets or regulatory liabilities on our Consolidated Balance Sheet (See Note 17. Pension and Other Postretirement Benefit Plans).


(c)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC

12 Months Ended

Dec. 31, 2013

Investment in ATC [Abstract]

Investment in ATC [Text Block]

INVESTMENT IN ATC

Investment in ATC. Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC rates are FERC-approved and are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2013, our equity investment in ATC was $114.6 million ($107.3 million at December 31, 2012). On January 30, 2014, we invested an additional $1.2 million in ATC. In total, we expect to invest approximately $5.8 million throughout 2014.



ALLETE’s Investment in ATC
Year Ended December 31	2013			2012
Millions
Equity Investment Beginning Balance		$107.3			$98.9
Cash Investments	3.1			4.7
Equity in ATC Earnings	20.3			19.4
Distributed ATC Earnings	(16.1		)	(15.7		)
Equity Investment Ending Balance		$114.6			$107.3

NOTE 6. INVESTMENT IN ATC (Continued)



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2013		2012
Millions
Current Assets		$80.7		$63.1
Non-Current Assets	3,509.5		3,274.7
Total Assets		$3,590.2		$3,337.8
Current Liabilities		$381.4		$251.5
Long-Term Debt	1,550.0		1,550.0
Other Non-Current Liabilities	126.2		95.8
Members’ Equity	1,532.6		1,440.5
Total Liabilities and Members’ Equity		$3,590.2		$3,337.8



Income Statement Data
Year Ended December 31	2013		2012		2011
Millions
Revenue		$626.3		$603.2		$567.2
Operating Expense	295.1		281.0		261.6
Other Expense	83.6		84.8		81.7
Net Income		$247.6		$237.4		$223.9
ALLETE’s Equity in Net Income		$20.3		$19.4		$18.4

- Definition

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

+ References+ Details

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2013
Acquisitions [Abstract]
Acquisitions [Text Block]	ACQUISITIONS On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake) and Condon, Oregon (Condon) from The AES Corporation (AES) for approximately $27.0 million, subject to a working capital adjustment. The acquisition was financed with cash from operations. The necessary FERC approvals were received in December 2013. ALLETE Clean Energy also has an option to acquire a fourth wind facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015. In November 2013, we made a deposit of $5.4 million for cash held in escrow for the acquisition of the three wind facilities, which is classified as restricted cash and included in Other Non-Current Assets on our Consolidated Balance Sheet. The Lake Benton, Storm Lake and Condon facilities have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake began commercial operations in 1999, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility from AES in June 2015. Armenia Mountain began operations in 2009. The purchase price will be allocated based on the estimated fair values of assets acquired and the liabilities assumed at the date of acquisition. The acquisition will be accounted for as a business combination. We are currently in the process of accounting for the acquisition, therefore, certain disclosures, including the allocation of the purchase price, will be included in the Form 10-Q for the period ending March 31, 2014.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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+ Details

Investments

12 Months Ended

Dec. 31, 2013

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At December 31, 2013, our long-term investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans, and other assets consisting primarily of land in Minnesota.

NOTE 8. INVESTMENTS (Continued)



Other Investments
As of December 31	2013		2012
Millions
ALLETE Properties		$89.9		$91.1
Available-for-sale Securities (a)	17.7		26.8
Cash Equivalents	34.2		20.7
Other	4.5		4.9
Total Other Investments		$146.3		$143.5


(a)	As of December 31, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.6 million, in one year to less than three years was $4.7 million, in three years to less than five years was $2.0 million, and in five or more years was $2.5 million.



ALLETE Properties	December 31, 2013			December 31, 2012
Millions
Land Inventory Beginning Balance		$86.5			$86.0
Cost of Sales	(1.5		)	(0.2		)
Other	0.4			0.7
Land Inventory Ending Balance	85.4			86.5
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4			1.4
Other	3.1			3.2
Total Real Estate Assets		$89.9			$91.1

Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value. Land values are reviewed for impairment on a quarterly basis. In 2013, impairment analyses of estimated undiscounted future net cash flows was conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. Consequently, there was no impairment recorded for the year ended December 31, 2013 (none for the year ended December 31, 2012).

Long-Term Finance Receivables. As of December 31, 2013, long-term finance receivables were $1.4 million net of allowance ($1.4 million net of allowance as of December 31, 2012). Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. As of December 31, 2013, we had allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2012).

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. Contract purchasers may incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they may have substantially more at risk than the deposit.

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.



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	(Loss)	Fair Value
2013	$18.3	—	$(0.6)	$17.7
2012	$27.4	$0.5	$(1.1)	$26.8
2011	$27.3	$0.1	$(2.7)	$24.7

NOTE 8. INVESTMENTS (Continued)



	Net	Gross Realized		Net Unrealized Gain (Loss) in Other
Year Ended December 31	Proceeds	Gain	(Loss)	Comprehensive Income
2013	$16.1	$2.2	—	—
2012	$1.5	—	—	$1.2
2011	$7.8	—	—	$(0.3)

Derivatives	12 Months Ended
Derivatives	Dec. 31, 2013
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES We have two variable-to-fixed interest rate swaps (Swaps), designated as cash flow hedges, in order to manage the interest rate risk associated with a $75.0 million Term Loan which represents approximately 7 percent of the Company’s outstanding long-term debt as of December 31, 2013. (See Note 11. Short-Term and Long-Term Debt.) The Swaps have effective dates of August 25, 2011, and August 26, 2014, and mature on August 25, 2014 and 2015, respectively. The Swaps involve the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreements at 0.825 percent and 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swaps are expected to be highly effective. If it is determined the Swaps cease to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessments of hedge effectiveness resulted in no ineffectiveness recorded for the year ended December 31, 2013. As of December 31, 2013, the fair value of the Swaps was a $0.6 million liability ($0.7 million liability as of December 31, 2012) of which $0.3 million ($0.7 million as of December 31, 2012) was included in other non-current liabilities and $0.3 million (zero as of December 31, 2012) was included in other current liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swaps were recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.

- Definition

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

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Fair Value

12 Months Ended

Dec. 31, 2013

Fair Value [Abstract]

Fair Value [Text Block]

FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). 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.

NOTE 10. FAIR VALUE (Continued)

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$7.9	—		—		$7.9
Available-for-sale Securities – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9

Liabilities:
Deferred Compensation	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5



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

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

There was no activity in Level 3 during the years ended December 31, 2013 or 2012.

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 years ended December 31, 2013 and 2012, there were no transfers in or out of Levels 1, 2 or 3.

NOTE 10. FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the items listed in the table 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 (Level 2).



Financial Instruments	Carrying Amount		Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2013		$1,110.2		$1,131.7
December 31, 2012		$1,018.1		$1,143.7

- Definition

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

+ References+ Details

Short-term and Long-term Debt

12 Months Ended

Dec. 31, 2013

Short-Term and Long-Term Debt [Abstract]

Short-Term and Long-Term Debt [Text Block]

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. Total short-term debt outstanding as of December 31, 2013, was $27.2 million ($84.5 million as of December 31, 2012) and consisted of long-term debt due within one year. Short-term debt as of December 31, 2012, included $60.0 million of long-term debt that matured in April 2013.

As of December 31, 2013, we had bank lines of credit aggregating $406.4 million ($406.4 million as of December 31, 2012), the majority of which expire in November 2018. We had $5.4 million outstanding in standby letters of credit under our lines of credit as of December 31, 2013 (none as of December 31, 2012).

On November 4, 2013, ALLETE entered into a $400.0 million credit agreement (Agreement) with JPMorgan Chase Bank, N.A. as Administrative Agent, and several other lenders that are parties thereto. The Agreement replaced our $250.0 million credit facility dated as of May 25, 2011, and our $150.0 million credit facility dated as of February 1, 2012, which were originally scheduled to expire on June 30, 2015, and January 31, 2014, respectively. The Agreement is unsecured and has a maturity date of November 2, 2018. At our request and subject to certain conditions, the Agreement may be increased by up to $150.0 million and we may make two requests, each for a one-year extension. Advances may be used for general corporate purposes, to provide liquidity in support of our commercial paper program and to issue up to $60.0 million in letters of credit.

Long-Term Debt. Total long-term debt outstanding as of December 31, 2013, was $1,083.0 million ($933.6 million as of December 31, 2012). The aggregate amount of long-term debt maturing during 2014 is $27.2 million ($143.0 million in 2015; $22.3 million in 2016; $51.8 million in 2017; $1.7 million in 2018; and $864.2 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgage collateralizing outstanding 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.

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



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

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

NOTE 11. SHORT-TERM AND LONG-TERM DEBT (Continued)

On August 26, 2013, we amended our $75.0 million Term Loan with JPMorgan Chase Bank, N.A. (Term Loan). The Term Loan was amended to extend the maturity date an additional year to August 25, 2015, and to lower the interest rate to the one-month LIBOR plus 0.875 percent. There was no change to the original interest rate swap agreement which remains in effect through August 25, 2014, and effectively fixes the interest rate for the amended Term Loan at 1.70 percent through August 25, 2014. We also entered into a new interest swap agreement covering the final year of the amended Term Loan which effectively fixes the interest rate at 1.625 percent from August 26, 2014, through August 25, 2015. (See also Note 9. Derivatives.)

On December 10, 2013, we agreed to sell $215.0 million in 2014 of ALLETE First Mortgage Bonds (Bonds) in the private placement market in four series as follows:



Issue Date (on or about)	Maturity Date	Principal Amount	Interest Rate
March 4, 2014	March 15, 2024	$60 Million	3.69%
March 4, 2014	March 15, 2044	$40 Million	4.95%
June 26, 2014	July 15, 2022	$75 Million	3.40%
June 26, 2014	July 15, 2044	$40 Million	5.05%

The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company intends to use the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures or for general corporate purposes. The Bonds will be sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

NOTE 11. SHORT-TERM AND LONG-TERM DEBT (Continued)



Long-Term Debt
As of December 31	2013		2012
Millions
First Mortgage Bonds
4.86% Series Due 2013	—			$60.0
6.94% Series Due 2014	$18.0		18.0
1.83% Series Due 2018	50.0		—
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		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		30.0
5.10% Series Due 2025	30.0		30.0
3.20% Series Due 2026	75.0		75.0
5.99% Series Due 2027	60.0		60.0
3.30% Series Due 2028	40.0		—
5.69% Series Due 2036	50.0		50.0
6.00% Series Due 2040	35.0		35.0
5.82% Series Due 2040	45.0		45.0
4.08% Series Due 2042	85.0		85.0
4.21% Series Due 2043	60.0		—
SWL&P First Mortgage Bonds 7.25% Series Due 2013	—		10.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		—
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 2020	24.6		27.5
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025	27.8		27.8
Unsecured Term Loan Variable Rate Due 2015	75.0		75.0
Other Long-Term Debt, 0.15% – 7.50% Due 2014 – 2037	41.8		41.8
Total Long-Term Debt	1,110.2		1,018.1
Less: Due Within One Year	27.2		84.5
Net Long-Term Debt		$1,083.0		$933.6

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive covenant requires ALLETE to maintain a ratio of its Indebtedness to Total Capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00 measured quarterly. As of December 31, 2013, our ratio was 0.45 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, 2013, ALLETE was in compliance with its financial covenants.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References+ Details

Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments, Guarantees and Contingencies [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

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

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract, subject to the provisions of the Minnkota Power sales agreement described below. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2013, Square Butte had total debt outstanding of $403.3 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the next five years, 2014 through 2018, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during 2013 was $71.1 million ($67.1 million in 2012; $61.2 million in 2011). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $10.5 million in 2013 ($11.1 million in 2012; $11.1 million in 2011). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

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

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

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

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

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2015. Under this agreement Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

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

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

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

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

Our 292 MW Bison Wind Energy Center, located in North Dakota, was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in an order dated December 3, 2013.

On September 25, 2013, the NDPSC approved the site permit for Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. As a result, construction has commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $55.6 million was spent through December 31, 2013. Our minimum payment obligation for 2014 is $244.4 million. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We anticipate including Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in the first quarter of 2014, which upon approval, authorizes updated rates to be included on customer bills.

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly the Thomson Energy Center, which is currently off-line due to damage to the forebay canal and flooding at the facility. Minnesota Power continues to work in close contact with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs, on restoring the Thomson facility and to rebuild the forebay embankment. The forebay rebuild cost is estimated to be approximately $25 million, of which $6.7 million is under contractual obligation for 2014. In addition to the forebay work, Minnesota Power is performing restoration and upgrade work on electrical, mechanical and flow line systems at the Thomson facility, which is estimated to cost a total of approximately $40 million (net of anticipated insurance recoveries). Any expenditures to restore and upgrade systems and rebuild the forebay canal will be capitalized. Minnesota Power is working towards returning to partial generation from the Thomson Energy Center by the first half of 2014 and to full generation by the end of 2014. In addition to the work at the Thomson facility, additional work on the Thomson Dam and other facilities in the St. Louis River hydro system are necessary to meet high flow events like that experienced in June 2012, which is estimated to cost approximately $15 million through 2015. A request seeking cost recovery of capital expenditures related to the restoration and repair of the Thomson facility and other related St. Louis River hydro system projects through a renewable resources rider is expected to be filed with the MPUC in 2014.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Currently, Minnesota Power is in discussions regarding the extension of our coal supply and transportation contracts beyond 2015. Our minimum annual payment obligation under these supply and transportation agreements is $35.3 million for 2014 and $2.2 million for 2015. Our minimum annual payment obligation will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2021. The aggregate amount of minimum lease payments for all operating leases is $12.1 million in 2014, $11.5 million in 2015, $9.5 million in 2016, $8.7 million in 2017, $7.4 million in 2018 and $29.2 million thereafter. Total rent and lease expense was $13.8 million in 2013 ($11.5 million in 2012; $9.4 million in 2011).

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

Transmission Investments. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. On November 12, 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We anticipate filing a petition in the first quarter of 2014 to include additional transmission investments and expenditures in customer billing rates.

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

Minnesota Power is participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed in August 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $100 million and $110 million in the CapX2020 initiative through 2015. A total of $80.5 million was spent through December 31, 2013, of which $69.6 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($48.2 million as of December 31, 2012 of which $37.3 million related to the Fargo, North Dakota to Monticello, Minnesota projects and $10.9 million related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

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

The GNTL is subject to various federal and state regulatory approvals. Before a large energy facility can be sited or constructed in Minnesota, the MPUC requires a Certificate of Need, which was filed on October 21, 2013. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020. Minnesota Power’s portion of capital expenditures for the GNTL is estimated to be approximately $300 million depending on the final route of the line, reflecting approximately 51 percent of the total line cost.

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.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

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

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

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

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

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

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

Due to legal challenges at both the State and Federal levels, there is currently no applicable compliance deadline for the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation date to bring Taconite Harbor Unit 3 into compliance. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC in an order dated November 12, 2013, we plan to retire Taconite Harbor Unit 3 in 2015. We believe that the Taconite Harbor Unit 3 retirement will be accomplished before any compliance deadline takes effect.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $310 million through 2016. Our minimum payment obligation for the environmental upgrade is $61.1 million for 2014 and $25.7 million for 2015. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in an order dated November 12, 2013, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015, to position the Company for MATS compliance. On January 9, 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS by approximately six weeks (until May 31, 2015), in order to align the Unit 3 retirement with MISO’s resource planning year.

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

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

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

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

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

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

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

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

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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


•	Expanding our renewable energy supply;


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


•	Improving efficiency of our energy generating facilities;


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


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

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

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

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

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

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

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

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. On October 15, 2013, the U.S. Supreme Court announced that it would grant review of the Circuit Court’s decision, with such review limited to the question of whether EPA’s regulation of GHGs under the PSD provisions of the Clean Air Act and the Tailoring Rule was permissible. The Supreme Court’s decision, which is expected in 2014, is not expected to affect EPA’s authority to regulate CO₂ from fossil fuel-fired electric generating units under the NSPS provisions of the Clean Air Act, but may affect the timing of such regulations.

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

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011, and the EPA expects to issue a final rule on April 17, 2014. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

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

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

Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its coal-fired electric generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. In June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash. The EPA has committed to publish the final rule by the end of 2014. We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.

Other Matters

BNI Coal. As of December 31, 2013, BNI Coal had surety bonds outstanding of $29.7 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit with CoBANK ACB for an additional $2.6 million to provide for BNI Coal’s total bonding reclamation obligation, which is currently estimated at $32.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of December 31, 2013, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

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

Legal Proceedings.

United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. In response to a Motion for Summary Judgment by Minnesota Power, the Court dismissed all of plaintiffs’ claims in an order dated August 21, 2013. On October 29, 2013, the plaintiffs’ appealed the decision to the Minnesota Court of Appeals. The Company has responded to the appeal. As of December 31, 2013, a potential loss is not currently probable or reasonably estimable.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of December 31, 2013, because a potential loss is not currently probable or reasonably estimable.

Other. We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

- Definition

The entire disclosure for commitments and contingencies.

+ References+ Details

Common Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2013

Common Stock and Earnings Per Share [Abstract]

Common Stock and Earnings Per Share [Text Block]

COMMON STOCK AND EARNINGS PER SHARE



Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2010	35,817		$636.1
Employee Stock Purchase Program	20	0.8
Invest Direct	437	17.2
Options and Stock Awards	109	6.7
Equity Issuance Program	400	16.0
Purchase of Non-Controlling Interest	222	8.8
Contributions to Pension	508	20.0
Balance as of December 31, 2011	37,513		$705.6
Employee Stock Purchase Program	20	0.8
Invest Direct	474	19.2
Options and Stock Awards	95	6.0
Equity Issuance Program	1,275	53.1
Balance as of December 31, 2012	39,377		$784.7
Employee Stock Purchase Program	16	0.7
Invest Direct	395	18.5
Options and Stock Awards	301	17.9
Equity Issuance Program	1,312	63.4
Balance as of December 31, 2013	41,401		$885.2

Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc. (successor to KCCI, Ltd.), in February 2008, as amended most recently in February 2014, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 3.1 million shares remain available for issuance. For the year ended December 31, 2013, 1.3 million shares of common stock were issued under this agreement resulting in net proceeds of $63.4 million (1.3 million shares for net proceeds of $53.1 million for the year ended December 31, 2012). The shares sold in 2011, 2012 and through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

Earnings Per Share. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units, and performance share awards granted under our Executive Long-Term Incentive Compensation Plans. In 2013, in accordance with accounting standards for earnings per share, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices. In 2012 and 2011, 0.2 million shares and 0.3 million shares were excluded because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.

Purchase of Non-Controlling Interest. In 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or comprehensive income.

Contributions to Pension. On January 10, 2014, we contributed approximately 0.4 million shares of ALLETE common stock to our pension plan, which had an aggregate value of $19.5 million when contributed. There were no contributions of ALLETE common stock to our pension plan in 2013 or 2012. In 2011, ALLETE contributed approximately 0.5 million shares of ALLETE common stock to its pension plan, which had an aggregate value of $20.0 million when contributed. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933.

NOTE 13. COMMON STOCK AND EARNINGS PER SHARE (Continued)



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2013
Net Income Attributable to ALLETE		$104.7			$104.7
Average Common Shares	39.7		0.1	39.8
Earnings Per Share		$2.64			$2.63
2012
Net Income Attributable to ALLETE		$97.1			$97.1
Average Common Shares	37.6		—	37.6
Earnings Per Share		$2.59			$2.58
2011
Net Income Attributable to ALLETE		$93.8			$93.8
Average Common Shares	35.3		0.1	35.4
Earnings Per Share		$2.66			$2.65

- Definition

The entire disclosure for earnings per share.

+ References+ Details

Income Tax Expense

12 Months Ended

Dec. 31, 2013

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2013			2012			2011
Millions
Current Tax Expense (Benefit)
Federal (a)	—			—			$1.4
State (a)	$0.1			$0.5			(1.6		)
Total Current Tax Expense (Benefit)	0.1			0.5			(0.2		)
Deferred Tax Expense
Federal (b)	22.9			37.0			27.4
State (b)	6.5			1.4			9.3
Investment Tax Credit Amortization	(0.8		)	(0.9		)	(0.9		)
Total Deferred Tax Expense	28.6			37.5			35.8
Total Income Tax Expense		$28.7			$38.0			$35.6

(a)

For the years ended December 31, 2013, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, and the American Taxpayer Relief Act of 2012. The federal and state NOLs will be carried forward to offset future taxable income.

(b)

For the year ended December 31, 2013, federal deferred tax expense is lower than the prior year primarily due to higher renewable tax credits. For the years ended December 31, 2013, 2012, and 2011, state deferred tax expense includes state renewable tax credits earned, net of valuation allowance, which will be carried forward to offset future state income taxes. The year ended December 31, 2011, included an income tax benefit for the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and a benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA.



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2013			2012			2011
Millions
Income Before Non-Controlling Interest and Income Taxes		$133.4			$135.1			$129.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$46.7			$47.3			$45.2
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	4.3			1.2			6.0
Deferred Accounting for Retail Portion of the PPACA	—			—			(2.9		)
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal	—			—			(6.2		)
Regulatory Differences for Utility Plant	(2.2		)	(2.2		)	(1.2		)
Production Tax Credits	(19.2		)	(7.6		)	(4.3		)
Other	(0.9		)	(0.7		)	(1.0		)
Total Income Tax Expense		$28.7			$38.0			$35.6

The effective tax rate on income was 21.5 percent for 2013 (28.1 percent for 2012; 27.6 percent for 2011). The 2013 and 2012 effective rates were primarily impacted by renewable tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above). The 2011 effective tax rate was primarily impacted by the deduction for AFUDC-Equity, the reversal of a deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, renewable tax credits, and the MPUC’s approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA.

NOTE 15. INCOME TAX EXPENSE (Continued)



Deferred Tax Assets and Liabilities
As of December 31	2013			2012
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$66.3			$120.2
Property Related	82.2			59.8
NOL Carryforwards	112.8			90.8
Tax Credit Carryforwards	55.1			28.3
Other	16.9			24.6
Gross Deferred Tax Assets	333.3			323.7
Deferred Tax Asset Valuation Allowance	(8.0		)	(2.4		)
Total Deferred Tax Assets		$325.3			$321.3
Deferred Tax Liabilities
Property Related		$656.2			$577.1
Regulatory Asset for Benefit Obligations	58.7			104.3
Unamortized Investment Tax Credits	11.1			11.9
Partnership Basis Differences	36.7			28.6
Other	22.7			30.1
Total Deferred Tax Liabilities		$785.4			$752.0
Net Deferred Income Taxes		$460.1			$430.7
Recorded as:
Net Current Deferred Tax Assets (a)		$19.0		—
Net Current Deferred Tax Liabilities (b)	—				$6.9
Net Long-Term Deferred Tax Liabilities	479.1			423.8
Net Deferred Income Taxes		$460.1			$430.7


(a)	In 2013, Current Deferred Tax Assets reflect the expectation of using federal NOL carryforward deductions in 2014.


(b)	Included in Other Current Assets and Other Current Liabilities.



NOL and Tax Credit Carryforwards
Year Ended December 31	2013	2012
Millions
Federal NOL Carryforwards (a)	$279.8		$244.1
Federal Tax Credit Carryforwards	$35.5	$16.0
State NOL Carryforwards (a)	$156.3	$90.6
State Tax Credit Carryforwards (b)	$11.9	$10.3


(a)	Pretax amounts


(b)	Net of $7.7 million valuation allowance.

In 2013, we generated federal and various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provision of the American Taxpayer Relief Act of 2012. The 2013 federal NOL will be utilized by carrying it forward to offset future years’ income. The federal NOL and tax credit carryforward periods expire between 2019 and 2032; included in the federal NOL carryforward are charitable contribution carryforwards which expire between 2014 and 2016. We expect to fully utilize the federal NOL, charitable contributions, and federal tax credit carryforwards; therefore no Federal valuation allowance has been recognized as of December 31, 2013.

The state NOLs 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 state NOL and tax credit carryforward periods expire between 2024 and 2032; included in the state NOL carryforwards are charitable contribution carryforwards which expire between 2014 and 2016.

NOTE 15. INCOME TAX EXPENSE (Continued)



Gross Unrecognized Income Tax Benefits	2013			2012			2011
Millions
Balance at January 1		$2.7			$11.4			$12.3
Additions for Tax Positions Related to the Current Year	0.1			—			—
Additions for Tax Positions Related to Prior Years	1.3			—			—
Reductions for Tax Positions Related to Prior Years	—			(8.7		)	(0.9		)
Reductions for Settlements	(2.9		)	—			—
Balance as of December 31		$1.2			$2.7			$11.4

Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The gross unrecognized tax benefits as of December 31, 2013, includes $0.2 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $2.9 million in 2013 was due to the removal of our uncertain tax positions for positions effectively settled with the IRS for tax years 2005 through 2009. The decrease in the unrecognized tax benefit balance of $8.7 million in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.

As of December 31, 2013, we had $0.5 million ($0.5 million for 2012 and $1.1 million for 2011) of accrued interest related to unrecognized tax benefits included in our Consolidated Balance Sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in our Consolidated Statement of Income. In 2013, we recognized no interest expense (decrease in interest expense of $0.6 million for 2012 and interest expense of $0.4 million for 2011). Increases to our interest expense during 2013 were offset by decreases related to the interest benefit associated with the NOL and tax credit carryforwards. There were no penalties recognized in 2013, 2012 or 2011.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has settled with the IRS for the audit of 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 $0.2 million due to the expiration of the statute of limitations. This amount is primarily due to temporary tax positions.

In September 2013 the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. The regulations are generally effective for tax years beginning January 1, 2014. As ALLETE is adopting certain utility-specific guidance for deductible repairs previously issued by the IRS, the issuance will not have a material impact on our consolidated financial statements.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References+ Details

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2013

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

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

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2013, were as follows:



	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
For the Year Ended December 31, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income Before Reclassifications	1.3		3.2	0.1	4.6
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(1.3	)	1.6	—	0.3
Net Other Comprehensive Income	—		4.8	0.1	4.9
Ending Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)	$(0.3)	$(17.1)

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2013, were as follows:



	Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	December 31,
	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$2.2
Income Taxes (b)	(0.9	)
Total, Net of Income Taxes	$1.3

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.8
Actuarial Gains and Losses (c)	(3.5	)
Total	(2.7	)
Income Taxes (b)	1.1
Total, Net of Income Taxes	$(1.6)
Total Reclassifications	$(0.3)


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


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


(c)	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense (See Note 17. Pension and Other Postretirement Benefit Plans).

- Definition

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

+ References+ Details

Pension and Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2013

Pension and Other Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

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. We made no contributions to the plans in 2013 ($7.3 million in 2012). We also have a defined contribution pension plan covering substantially all employees. The 2013 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $8.4 million ($7.7 million for the 2012 plan year). On January 10, 2014, we contributed $19.5 million to the defined benefit pension plan, all of which was contributed in shares of ALLETE common stock. (See Note 13. Common Stock and Earnings Per Share and Note 18. Employee Stock and Incentive Plans).

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

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 require employees to be at least age 55 with 10 years of participation in the plan. 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 an irrevocable grantor trust. In 2013, $10.8 million was contributed to the VEBAs and $2.0 million was contributed to the grantor trust. In 2012, we contributed $1.5 million to the VEBAs and no contributions were made 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. Contributions are based on estimates and assumptions which are subject to change. We do not expect to make any additional contributions to the defined benefit pension plan in 2014, beyond the $19.5 million contribution to the defined benefit pension plan made in January 2014. We do not expect to make any contributions to the defined benefit postretirement health and life plan in 2014.

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 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 are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) 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 (regulatory liability) on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Pension Obligation and Funded Status
Year Ended December 31	2013			2012
Millions
Accumulated Benefit Obligation		$577.6			$598.7
Change in Benefit Obligation
Obligation, Beginning of Year		$652.1			$597.5
Service Cost	9.9			9.1
Interest Cost	26.0			26.4
Actuarial (Gain) Loss	(49.2		)	38.5
Benefits Paid	(33.5		)	(30.9		)
Participant Contributions	17.5			11.5
Obligation, End of Year		$622.8			$652.1
Change in Plan Assets
Fair Value, Beginning of Year		$460.1			$432.4
Actual Return on Plan Assets	56.5			38.7
Employer Contribution (a)	18.5			19.9
Benefits Paid	(33.5		)	(30.9		)
Fair Value, End of Year		$501.6			$460.1
Funded Status, End of Year	$(121.2)			$(192.0)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(120.1)			$(190.9)


(a)	Includes participant contributions noted above.

The pension costs that are reported as a component within our Consolidated Balance Sheet, reflected in long-term regulatory assets or liabilities and accumulated other comprehensive income, consist of the following:



Unrecognized Pension Costs
Year Ended December 31	2013		2012
Millions
Net Loss		$194.9		$286.8
Prior Service Cost	0.4		0.7
Total Unrecognized Pension Costs		$195.3		$287.5



Components of Net Periodic Pension Expense
Year Ended December 31	2013			2012			2011
Millions
Service Cost		$9.9			$9.1			$7.6
Interest Cost	26.0			26.4			27.4
Expected Return on Plan Assets	(35.2		)	(35.4		)	(34.6		)
Amortization of Loss	21.5			17.5			12.1
Amortization of Prior Service Cost	0.3			0.3			0.3
Net Pension Expense		$22.5			$17.9			$12.8

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2013		2012
Millions
Net (Gain) Loss	$(70.4)			$35.2
Amortization of Prior Service Cost	(0.3	)	(0.3		)
Amortization of Loss	(21.5	)	(17.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(92.2)			$17.4



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31	2013		2012
Millions
Projected Benefit Obligation		$622.8		$652.1
Accumulated Benefit Obligation		$577.6		$598.7
Fair Value of Plan Assets		$501.6		$460.1



Postretirement Health and Life Obligation and Funded Status
Year Ended December 31	2013			2012
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$168.8			$210.6
Service Cost	3.9			4.2
Interest Cost	6.8			9.4
Actuarial Gain	(18.8		)	(43.2		)
Participant Contributions	2.7			2.6
Plan Amendments	—			(5.3		)
Benefits Paid	(9.9		)	(9.5		)
Settlements (a)	(1.6		)	—
Obligation, End of Year		$151.9			$168.8
Change in Plan Assets
Fair Value, Beginning of Year		$131.0			$121.0
Actual Return on Plan Assets	21.4			14.3
Employer Contribution	11.7			2.3
Participant Contributions	2.7			2.5
Benefits Paid	(9.8		)	(9.1		)
Fair Value, End of Year		$157.0			$131.0
Funded Status, End of Year	$5.1			$(37.8)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$19.4			—
Current Liabilities	$(0.9)			$(0.8)
Non-Current Liabilities	$(13.4)			$(37.0)


(a)	Result of the exit from a legacy benefit plan.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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 $17.8 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2013 ($22.1 million at December 31, 2012).

The postretirement health and life costs that are reported as a component within our Consolidated Balance Sheet, reflected in regulatory long-term assets or liabilities and accumulated other comprehensive income, consist of the following:



Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2013		2012
Millions
Net (Gain) Loss	$(9.0)			$23.5
Prior Service Credit	(10.1	)	(13.1		)
Total Unrecognized Postretirement Health and Life Costs (Credit)	$(19.1)			$10.4



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2013			2012			2011
Millions
Service Cost		$3.9			$4.2			$3.8
Interest Cost	6.8			9.4			10.8
Expected Return on Plan Assets	(9.7		)	(9.9		)	(9.7		)
Amortization of Prior Service Credit	(2.5		)	(1.7		)	(1.7		)
Amortization of Loss	1.6			7.5			8.5
Amortization of Transition Obligation	—			0.1			0.1
Effect of Plan Settlement (a)	(1.6		)	—			—
Net Postretirement Health and Life Expense (Credit)	$(1.5)				$9.6			$11.8


(a)	Result of the exit from a legacy benefit plan.



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2013		2012
Millions
Net Gain	$(30.2)		$(47.5)
Prior Service Credit Arising During the Period	—		(5.3	)
Amortization of Prior Service Credit	2.5		1.7
Amortization of Transition Obligation	—		(0.1	)
Amortization of Loss	(1.6	)	(7.5	)
Amount Recognized due to Plan Settlement (a)	(0.2	)	—
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(29.5)		$(58.7)


(a)	Result of the exit from a legacy benefit plan.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Estimated Future Benefit Payments
	Pension		Postretirement Health and Life
Millions
2014		$33.9		$7.7
2015		$34.9		$8.4
2016		$35.8		$8.8
2017		$36.9		$9.2
2018		$37.8		$9.4
Years 2019 – 2023		$200.2		$50.6

The pension and postretirement health and life costs recorded in regulatory long-term assets or liabilities 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, 2014, are as follows:



	Pension		Postretirement Health and Life
Millions
Net Loss		$14.2		$0.5
Prior Service Cost (Credit)	0.3		(2.5		)
Total Pension and Postretirement Health and Life Cost (Credit)		$14.5	$(2.0)



Weighted-Average Assumptions Used to Determine Benefit Obligation
As of December 31	2013	2012
Discount Rate
Pension	4.93%	4.10%
Postretirement Health and Life	4.96%	4.13%
Rate of Compensation Increase	3.7 - 4.3%	4.3 - 4.6%
Health Care Trend Rates
Trend Rate	7.25%	9.25%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2020	2019



Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2013	2012	2011
Discount Rate	4.10 - 4.13%	4.54 - 4.56%	5.36 - 5.40%
Expected Long-Term Return on Plan Assets (a)
Pension	8.25%	8.25%	8.5%
Postretirement Health and Life	6.6 - 8.25%	6.6 - 8.25%	6.8 - 8.5%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%	4.3 - 4.6%


(a)	The expected long-term rate of return used to determine net periodic benefit expense for 2014 has been reduced to 8.00 percent.

In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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 Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.6	$(1.3)
Effect on Postretirement Health and Life Obligation		$16.0	$(13.4)



Actual Plan Asset Allocations
	Pension				Postretirement Health and Life (a)
	2013		2012		2013		2012
Equity Securities	52	%	54	%	63	%	56	%
Debt Securities	34	%	28	%	29	%	35	%
Private Equity	9	%	13	%	8	%	9	%
Real Estate	5	%	5	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities at December 31, 2013 (no shares in 2012). On January 10, 2014, $19.5 million (0.4 million shares) of ALLETE common stock was contributed to the pension plan.

At the end of 2013, the defined benefit pension plan adopted a dynamic asset allocation strategy (glide path) that increases the invested allocation to fixed income assets as the funding level of the plan increases to better match the sensitivity of the plan’s assets and liabilities to changes in interest rates. This is expected to reduce the volatility of reported pension plan expenses. The postretirement health and life plans’ assets continue to be diversified to achieve strong returns within managed risk. 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. Below are the current targeted allocations as of December 31, 2013.



Plan Asset Target Allocations
	Pension		Postretirement Health and Life (a)
Equity Securities	52	%	50	%
Debt Securities	30	%	30	%
Private Equity	9	%	10	%
Real Estate	9	%	10	%
	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value

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 various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.

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. This category includes various bonds and non-public funds whose underlying investments may be level 1 or level 2 securities.

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 private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

Pension Fair Value



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$20.9		$59.3	—			$80.2
U.S. Mid-cap Growth (a)	9.4		26.7		—		36.1
U.S. Small-cap (a)	9.9		28.2		—		38.1
International	61.2		43.5		—		104.7
Debt Securities:
Mutual Funds	130.1		—		—		130.1
Fixed Income	—		36.4		—		36.4
Cash Equivalents	2.7		—		—		2.7
Other Types of Investments:
Private Equity Funds	—		—			$46.8	46.8
Real Estate	—		—		26.5		26.5
Total Fair Value of Assets		$234.2		$194.1		$73.3		$501.6

(a)

The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, 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.

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2012		$58.9			$24.9
Actual Return on Plan Assets	2.3			2.1
Purchases, sales, and settlements, net	(14.4		)	(0.5		)
Balance as of December 31, 2013		$46.8			$26.5



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$43.0		$36.0	—			$79.0
U.S. Mid-cap Growth (a)	18.3		15.3		—		33.6
U.S. Small-cap (a)	18.3		15.3		—		33.6
International	50.5		45.9		—		96.4
Debt Securities:
Mutual Funds	72.5		—		—		72.5
Fixed Income	10.4		50.8		—		61.2
Other Types of Investments:
Private Equity Funds	—		—			$58.9	58.9
Real Estate	—		—		24.9		24.9
Total Fair Value of Assets		$213.0		$163.3		$83.8		$460.1

(a)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2011		$69.0			$21.7
Actual Return on Plan Assets	(9.7		)	3.4
Purchases, sales, and settlements, net	(0.4		)	(0.2		)
Balance as of December 31, 2012		$58.9			$24.9

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)

Postretirement Health and Life Fair Value



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$28.3	—		—			$28.3
U.S. Mid-cap Growth (a)	17.6		—		—		17.6
U.S. Small-cap (a)	18.2		—		—		18.2
International	33.4		—		—		33.4
Debt Securities:
Mutual Funds	30.8		—		—		30.8
Fixed Income	—			$15.5	—		15.5
Cash Equivalents	0.1		—		—		0.1
Other Types of Investments:
Private Equity Funds	—		—			$13.1	13.1
Total Fair Value of Assets		$128.4		$15.5		$13.1		$157.0


(a)	The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2012		$13.5
Actual Return on Plan Assets	2.4
Purchases, sales, and settlements, net	(2.8		)
Balance as of December 31, 2013		$13.1



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$16.7	—		—			$16.7
U.S. Mid-cap Growth (a)	13.2		—		—		13.2
U.S. Small-cap (a)	13.3		—		—		13.3
International	30.3		—		—		30.3
Debt Securities:
Mutual Funds	25.5		—		—		25.5
Fixed Income	0.2			$18.3	—		18.5
Other Types of Investments:
Private Equity Funds	—		—			$13.5	13.5
Total Fair Value of Assets		$99.2		$18.3		$13.5		$131.0


(a)	The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Fair Value (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2011		$14.0
Actual Return on Plan Assets	0.2
Purchases, sales, and settlements, net	(0.7		)
Balance as of December 31, 2012		$13.5

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.

Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2013

Employee Stock and Incentive Plans [Abstract]

Employee Stock and Incentive Plans [Text Block]

EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor a leveraged ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire. In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use 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 the 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 $8.4 million in 2013 ($7.7 million in 2012; $7.4 million in 2011).

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered 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	2013		2012		2011
Millions
ESOP Shares
Allocated	2.0		2.2		2.2
Unallocated	0.5		0.7		1.0
Total	2.5		2.9		3.2
Fair Value of Unallocated Shares		$24.1		$28.7		$42.0

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 0.9 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, 2013.

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

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

Non-Qualified Stock Options. These 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 canceled 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. Stock options have not been granted under our Executive Plan since 2008.

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 for retirement eligible participants vest monthly over a three-year period. For non-retirement eligible participants, shares vest at the end of the 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 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 earned. 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	2013		2012		2011
Millions
Performance Shares		$1.7		$1.4		$1.1
Restricted Stock Units	0.7		0.7		0.5
Total Share-Based Compensation Expense		$2.4		$2.1		$1.6
Income Tax Benefit		$1.0		$0.9		$0.7

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized stock-based compensation costs at December 31, 2013, 2012, or 2011.

As of December 31, 2013, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.7 million and $0.7 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years for performance share awards and 1.7 years for restricted stock units.

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2013.



	2013			2012			2011
	Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price
Outstanding as of January 1,	395,678		$42.28	460,234		$41.68	560,887		$40.69
Granted (a)	—	—		—	—		—	—
Exercised	287,379		$41.60	49,075		$35.84	80,798		$34.25
Forfeited	—	—		15,481		$44.86	19,855		$43.96
Outstanding as of December 31,	108,299		$44.10	395,678		$42.28	460,234		$41.68
Exercisable as of December 31,	108,299		$43.17	395,678		$41.71	460,234		$41.59


(a)	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Cash received from non-qualified stock options exercised was approximately $11.4 million in 2013. 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 $2.2 million during 2013 ($0.3 million in 2012; $0.5 million in 2011).



	Range of Exercise Price
As of December 31, 2013	$37.76 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	44,263		64,036
Weighted Average Remaining Contractual Life (Years)	2.6		2.7
Weighted Average Exercise Price		$40.18		$46.81

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2013.



	2013				2012				2011
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1,	107,899			$40.73	128,333			$36.54	122,489			$38.15
Granted (a)	45,830			$52.15	38,764			$44.70	39,312			$41.00
Awarded	(18,605	)		$35.10	(41,009	)		$34.25	(32,368	)		$48.10
Unearned Grant Award	(18,606	)		$35.10	(17,575	)		$34.25	—		—
Forfeited	(1,753	)		$47.26	(614	)		$34.49	(1,100	)		$34.35
Non-vested as of December 31,	114,765			$47.02	107,899			$40.73	128,333			$36.54

(a) Shares granted includes accrued dividends.

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were 41,332 and 43,081 performance shares granted in January 2013 and 2014, for the three-year performance periods ending in 2015 and 2016, respectively. 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 shares granted was $2.2 million and $2.0 million, respectively.

There were $18,605 and 36,515 performance shares awarded in February 2013 and 2014, for the three-year performance periods ending in 2012 and 2013, respectively. The grant date fair value of the shares awarded was $0.7 million and $1.5 million, respectively.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2013.



	2013				2012				2011
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1,	56,415			$36.61	63,464			$32.57	43,803			$30.61
Granted (a)	21,440			$43.41	18,162			$40.83	20,136			$36.74
Awarded	(20,939	)		$32.03	(24,707	)		$29.43	(215	)		$30.30
Forfeited	(934	)		$41.02	(504	)		$31.80	(260	)		$29.41
Available as of December 31,	55,982			$40.85	56,415			$36.61	63,464			$32.57

(a) Shares granted includes accrued dividends.

There were 19,193 and 17,491 restricted stock units granted in January 2013 and 2014, for the vesting periods ending in 2015 and 2016, respectively. The grant date fair value of the restricted stock units granted was $0.8 million and $0.9 million, respectively.

There were 20,939 restricted stock units awarded in 2013. The grant date fair value of the shares awarded was $0.7 million.

There were 18,860 restricted stock units awarded in February 2014. The grant date fair value of the shares awarded was $0.7 million.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References+ Details

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited) [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED)

Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.



Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2013
Operating Revenue		$263.8		$235.6		$251.0		$268.0
Operating Income		$44.4		$24.4		$38.4		$46.9
Net Income Attributable to ALLETE		$32.5		$14.0		$25.2		$33.0
Earnings Per Share of Common Stock
Basic		$0.83		$0.36		$0.63		$0.82
Diluted		$0.83		$0.35		$0.63		$0.82
2012
Operating Revenue		$240.0		$216.4		$248.8		$256.0
Operating Income		$38.4		$23.3		$45.6		$47.9
Net Income Attributable to ALLETE		$24.4		$14.4		$29.4		$28.9
Earnings Per Share of Common Stock
Basic		$0.66		$0.39		$0.78		$0.76
Diluted		$0.66		$0.39		$0.78		$0.75

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References+ Details

Schedule II

12 Months Ended

Dec. 31, 2013

Schedule II [Abstract]

Schedule II [Text Block]

Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves



	Balance at Beginning of Period		Additions			Deductions from Reserves (a)		Balance at End of Period
	Balance at Beginning of Period		Charged to Income		Other Charges	Deductions from Reserves (a)		Balance at End of Period
Millions
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2011 Trade Accounts Receivable		$0.9		$1.3	—		$1.3		$0.9
Finance Receivables – Long-Term		$0.8		$0.1	—		$0.3		$0.6
2012 Trade Accounts Receivable		$0.9		$1.0	—		$0.9		$1.0
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
2013 Trade Accounts Receivable		$1.0	1.3		—	1.2			$1.1
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
Deferred Asset Valuation Allowance
2011 Deferred Tax Assets		$0.5	$(0.1)		—	—			$0.4
2012 Deferred Tax Assets		$0.4	$2.0		—	—			$2.4
2013 Deferred Tax Assets		$2.4		$5.6	—	—			$8.0


(a)	Includes uncollectible accounts written off.

Operations and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Operations and Significant Accounting Policies [Abstract]
Financial Statement Preparation [Policy Text Block]	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 [Policy Text Block]	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 [Policy Text Block]	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 [Policy Text Block]	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.
Revenue Recognition [Policy Text Block]	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. 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 yet 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 transmission, renewable energy and environmental 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. BNI Coal recognizes revenue when coal is delivered. We account for revenue from our cost recovery riders (renewable resources, transmission and environmental improvement) in accordance with the accounting standards for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows automatic adjustment of future rates, the amount of the revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. Revenue recognized using the alternative revenue program guidance is included in operating revenue on our Consolidated Statement of Income and regulatory assets on our Consolidated Balance Sheet until it is subsequently collected from customers. Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.
Land Inventory [Policy Text Block]	Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, and are 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 sold 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 are recorded and the related assets are adjusted to their estimated fair value.
Cash and Cash Equivalents [Policy Text Block]	Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.
Accounts Receivable [Policy Text Block]	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.
Long-Term Finance Receivables [Policy Text Block]	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 receivables 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.
Available-for-Sale Securities [Policy Text Block]	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.
Inventories [Policy Text Block]	Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.
Property, Plant and Equipment [Policy Text Block]	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. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.
Impairment of Long-Lived Assets [Policy Text Block]	In the event that projected undiscounted future net cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset’s fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value of the asset is less than its carrying value, its carrying value is reduced and an impairment charge is recorded in the current period. Impairment of Long-Lived Assets. Land inventory is accounted for as held for use and is recorded at cost. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, may vary among each land parcel or bulk sale, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material. Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value. Land values are reviewed for impairment on a quarterly basis.
Derivatives [Policy Text Block]	Other Non-Current Assets. As of December 31, 2013, included in other non-current assets on the Consolidated Balance Sheet was restricted cash of $5.4 million related to cash held in escrow pending closing of the acquisition of wind energy facilities by ALLETE Clean Energy, which occurred on January 30, 2014. (See Note 7. Acquisitions.) Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings. Changes in the fair value of the Swaps were recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. Cash flows from the Swaps are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to the Swaps will be recorded in earnings when the hedged transactions occur or when it is probable they will not occur. Gains or losses on the interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.
Accounting for Stock-Based Compensation [Policy Text Block]	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.
Environmental Liabilities [Policy Text Block]	Environmental Liabilities. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.
Unamortized Discount and Premium on Debt [Policy Text Block]	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 which approximates the effective interest method.
Income Taxes [Policy Text Block]	Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return and combined and separate state income tax returns. 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. Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria.
Excise Taxes [Policy Text Block]	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.
Asset Retirement Obligations [Policy Text Block]	We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction or development and/or normal operation of the asset.
Regulatory Assets and Liabilities [Policy Text Block]	Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities represent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.
Equity Method Investments, Policy [Policy Text Block]	We account for our investment in ATC under the equity method of accounting.
Fair Value Measurement [Policy Text Block]	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. 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.
Fair Value Transfers [Policy Text Block]	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.
Pension and Other Postretirement Benefit Plans [Policy Text Block]	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 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 are not recognized as components of net periodic benefit cost. The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) 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 (regulatory liability) on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other non-rate base operations are recognized in accumulated other comprehensive income. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return. 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.
Employee Stock Ownership Plan (ESOP) [Policy Text Block]	According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants. 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 the 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.

Operations and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Operations and Significant Accounting Policies [Abstract]

Supplemental Statement of Cash Flow Information [Table Text Block]

Supplemental Statement of Cash Flow Information



Consolidated Statement of Cash Flows
Year Ended December 31	2013		2012		2011
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$47.5		$42.7		$43.2
Cash Paid (Received) During the Period for Income Taxes (a)		$0.5	—		$(11.4)
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$8.3		$20.2	$5.9
Increase (Decrease) in Capitalized Asset Retirement Costs	$(0.7)			$17.1		$0.3
AFUDC – Equity		$4.6		$5.1		$2.5
ALLETE Common Stock Contributed to the Pension Plan	—		—		$(20.0)


(a)	Due to bonus depreciation provisions in 2010 and 2012 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and in 2011, refunds were received from NOL carrybacks against prior years’ taxable income.

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2013		2012
Millions
Trade Accounts Receivable
Billed		$78.7		$70.4
Unbilled	18.7		17.4
Less: Allowance for Doubtful Accounts	1.1		1.0
Total Trade Accounts Receivable	96.3		86.8
Income Taxes Receivable	—		2.2
Total Accounts Receivable - Net		$96.3		$89.0

Inventories [Table Text Block]



Inventories
As of December 31	2013		2012
Millions
Fuel (a)		$13.1		$28.0
Materials and Supplies	46.2		41.8
Total Inventories		$59.3		$69.8


(a)	Fuel inventory was lower in 2013 primarily due to higher than expected thermal generation and the timing of coal shipments.

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets
As of December 31	2013		2012
Millions
Deferred Fuel Adjustment Clause		$23.0		$22.5
Other	12.1		11.1
Total Prepayments and Other Current Assets		$35.1		$33.6

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



Other Current Liabilities
As of December 31	2013		2012
Millions
Customer Deposits		$26.0		$28.8
Other	26.6		33.8
Total Other Current Liabilities		$52.6		$62.6



Other Non-Current Liabilities
As of December 31	2013		2012
Millions
Asset Retirement Obligation		$81.8		$77.9
Other	45.4		45.4
Total Other Non-Current Liabilities		$127.2		$123.3

Business Segments (Tables)

12 Months Ended

Dec. 31, 2013

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
2011
Operating Revenue		$928.2			$851.9			$76.3
Fuel and Purchased Power Expense	306.6			306.6			—
Operating and Maintenance Expense	381.2			301.5			79.7
Depreciation Expense	90.4			85.4			5.0
Operating Income (Loss)	150.0			158.4			(8.4		)
Interest Expense	(43.6		)	(35.8		)	(7.8		)
Equity Earnings in ATC	18.4			18.4			—
Other Income	4.4			2.6			1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	129.2			143.6			(14.4		)
Income Tax Expense (Benefit)	35.6			43.2			(7.6		)
Net Income (Loss)	93.6			100.4			(6.8		)
Less: Non-Controlling Interest in Subsidiaries	(0.2		)	—			(0.2		)
Net Income (Loss) Attributable to ALLETE		$93.8			$100.4		$(6.6)
Total Assets		$2,876.0			$2,579.8			$296.2
Capital Additions		$246.8			$228.0			$18.8



	Consolidated			Regulated Operations			Investments and Other
Millions
2013
Operating Revenue		$1,018.4			$925.5			$92.9
Fuel and Purchased Power Expense	334.8			334.8			—
Operating and Maintenance Expense	412.9			322.4			90.5
Depreciation Expense	116.6			110.2			6.4
Operating Income (Loss)	154.1			158.1			(4.0		)
Interest Expense	(50.3		)	(42.1		)	(8.2		)
Equity Earnings in ATC	20.3			20.3			—
Other Income	9.3			4.7			4.6
Income (Loss) Before Income Taxes	133.4			141.0			(7.6		)
Income Tax Expense (Benefit)	28.7			36.1			(7.4		)
Net Income (Loss)		$104.7			$104.9		$(0.2)
Total Assets		$3,476.8			$3,160.8			$316.0
Capital Additions		$339.5			$326.3			$13.2



	Consolidated			Regulated Operations			Investments and Other
Millions
2012
Operating Revenue		$961.2			$874.4			$86.8
Fuel and Purchased Power Expense	308.7			308.7			—
Operating and Maintenance Expense	397.1			310.0			87.1
Depreciation Expense	100.2			93.9			6.3
Operating Income (Loss)	155.2			161.8			(6.6		)
Interest Expense	(45.5		)	(39.8		)	(5.7		)
Equity Earnings in ATC	19.4			19.4			—
Other Income	6.0			5.1			0.9
Income (Loss) Before Income Taxes	135.1			146.5			(11.4		)
Income Tax Expense (Benefit)	38.0			50.4			(12.4		)
Net Income		$97.1			$96.1			$1.0
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References+ Details

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment [Table Text Block]



Property, Plant and Equipment
As of December 31	2013			2012
Millions
Regulated Utility		$3,380.0			$3,232.9
Construction Work in Progress	303.9			151.8
Accumulated Depreciation	(1,181.7		)	(1,102.8		)
Regulated Utility Plant - Net	2,502.2			2,281.9
Non-Rate Base Energy Operations	131.3			118.0
Construction Work in Progress	3.4			4.2
Accumulated Depreciation	(60.4		)	(56.7		)
Non-Rate Base Energy Operations Plant - Net	74.3			65.5
Other Plant - Net	—			0.2
Property, Plant and Equipment - Net		$2,576.5			$2,347.6

Estimated Useful Lives of Property, Plant and Equipment [Table Text Block]



Estimated Useful Lives of Property, Plant and Equipment
Generation	5 to 35 years	Distribution	14 to 65 years
Transmission	42 to 61 years	Other Plant	5 to 25 years

Asset Retirement Obligation [Table Text Block]



Asset Retirement Obligation
Millions
Obligation as of December 31, 2011		$57.0
Accretion Expense	3.8
Revisions in estimated cash flows	17.1
Obligation as of December 31, 2012	77.9
Accretion Expense	4.6
Revisions in estimated cash flows	(0.7		)
Obligation as of December 31, 2013		$81.8

Jointly-Owned Facilities and Projects (Tables)

12 Months Ended

Dec. 31, 2013

Jointly-Owned Facilities and Projects [Abstract]

Jointly-Owned Facilities and Projects [Table Text Block]

As of December 31, 2013 our investments in jointly-owned facilities and projects and the related ownership percentages are as follows:



Regulated Utility Plant	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
Boswell Unit 4		$416.1		$197.5		$71.5	80
CapX2020 Projects	22.8		1.0		57.7		9.3 - 14.7
Total		$438.9		$198.5		$129.2

- Definition

Tabular disclosure of proportionate interests in jointly owned utility plants. Includes the amount of plants in service, the accumulated provision for depreciation (if available), the amount of plants under construction, and the proportionate share. The amounts presented may be further subdivided to show amounts applicable to plant subcategories (for example, production, transmission, distribution). Includes statements that the amounts represent the utility's share in each joint plant and that it must provide its own financing. Information concerning two or more generating plants on the same site may be combined. States that the utility's share of direct expenses of the joint plants is included in the corresponding operating expenses on its income statement (for example, fuel, maintenance of plant, other operating expense). If the share of direct expenses is charged to purchased power, then disclose the amount so charged and the proportionate amounts charged to specific operating expenses on the records maintained for the joint plants.

+ References+ Details

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2013		2012
Millions
Current Regulatory Assets (a)
Deferred Fuel		$23.0		$22.5
Total Current Regulatory Assets	23.0		22.5
Non-Current Regulatory Assets
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans (b)	164.1		260.7
Income Taxes	35.3		36.0
Asset Retirement Obligation	16.0		12.1
Cost Recovery Riders (c)	39.6		18.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	—		4.3
Other	3.8		3.7
Total Non-Current Regulatory Assets	263.8		340.3

Total Regulatory Assets		$286.8		$362.8

Non-Current Regulatory Liabilities
Income Taxes		$17.0		$19.5
Plant Removal Obligations	19.7		18.1
Wholesale and Retail Contra AFUDC	19.7		15.5
Defined Benefit Pension and Other Postretirement Plans (b)	16.3		—
Other	8.3		7.0
Total Non-Current Regulatory Liabilities		$81.0		$60.1


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


(b)	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, are recognized as regulatory assets or regulatory liabilities on our Consolidated Balance Sheet (See Note 17. Pension and Other Postretirement Benefit Plans).


(c)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC (Tables)

12 Months Ended

Dec. 31, 2013

Investment in ATC [Abstract]

ALLETE's Interest in ATC [Table Text Block]



ALLETE’s Investment in ATC
Year Ended December 31	2013			2012
Millions
Equity Investment Beginning Balance		$107.3			$98.9
Cash Investments	3.1			4.7
Equity in ATC Earnings	20.3			19.4
Distributed ATC Earnings	(16.1		)	(15.7		)
Equity Investment Ending Balance		$114.6			$107.3

ATC Summarized Financial Data [Table Text Block]



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2013		2012
Millions
Current Assets		$80.7		$63.1
Non-Current Assets	3,509.5		3,274.7
Total Assets		$3,590.2		$3,337.8
Current Liabilities		$381.4		$251.5
Long-Term Debt	1,550.0		1,550.0
Other Non-Current Liabilities	126.2		95.8
Members’ Equity	1,532.6		1,440.5
Total Liabilities and Members’ Equity		$3,590.2		$3,337.8



Income Statement Data
Year Ended December 31	2013		2012		2011
Millions
Revenue		$626.3		$603.2		$567.2
Operating Expense	295.1		281.0		261.6
Other Expense	83.6		84.8		81.7
Net Income		$247.6		$237.4		$223.9
ALLETE’s Equity in Net Income		$20.3		$19.4		$18.4

Investments (Tables)

12 Months Ended

Dec. 31, 2013

Investments [Abstract]

Other Investments and ALLETE Properties [Table Text Block]



Other Investments
As of December 31	2013		2012
Millions
ALLETE Properties		$89.9		$91.1
Available-for-sale Securities (a)	17.7		26.8
Cash Equivalents	34.2		20.7
Other	4.5		4.9
Total Other Investments		$146.3		$143.5


(a)	As of December 31, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.6 million, in one year to less than three years was $4.7 million, in three years to less than five years was $2.0 million, and in five or more years was $2.5 million.



ALLETE Properties	December 31, 2013			December 31, 2012
Millions
Land Inventory Beginning Balance		$86.5			$86.0
Cost of Sales	(1.5		)	(0.2		)
Other	0.4			0.7
Land Inventory Ending Balance	85.4			86.5
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.4			1.4
Other	3.1			3.2
Total Real Estate Assets		$89.9			$91.1

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	(Loss)	Fair Value
2013	$18.3	—	$(0.6)	$17.7
2012	$27.4	$0.5	$(1.1)	$26.8
2011	$27.3	$0.1	$(2.7)	$24.7

Available-for-sale Securities [Table Text Block]



	Net	Gross Realized		Net Unrealized Gain (Loss) in Other
Year Ended December 31	Proceeds	Gain	(Loss)	Comprehensive Income
2013	$16.1	$2.2	—	—
2012	$1.5	—	—	$1.2
2011	$7.8	—	—	$(0.3)

- Definition

Tabular disclosure of available-for-sale securities which includes, but is not limited to, changes in the cost basis and fair value, fair value and gross unrealized gain (loss), fair values by type of security, contractual maturity and classification, amortized cost basis, contracts to acquire securities to be accounted for as available-for-sale, debt maturities, transfers to trading, change in net unrealized holding gain (loss) net of tax, continuous unrealized loss position fair value, aggregate losses qualitative disclosures, other than temporary impairment (OTTI) losses or other disclosures related to available for sale securities.

+ References+ Details

Fair Value (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$7.9	—		—		$7.9
Available-for-sale Securities – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9

Liabilities:
Deferred Compensation	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5



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

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount		Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2013		$1,110.2		$1,131.7
December 31, 2012		$1,018.1		$1,143.7

- Definition

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

+ References+ Details

Short-Term and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Short-Term and Long-Term Debt [Abstract]

Long-term Debt [Table Text Block]

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



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



Long-Term Debt
As of December 31	2013		2012
Millions
First Mortgage Bonds
4.86% Series Due 2013	—			$60.0
6.94% Series Due 2014	$18.0		18.0
1.83% Series Due 2018	50.0		—
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		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		30.0
5.10% Series Due 2025	30.0		30.0
3.20% Series Due 2026	75.0		75.0
5.99% Series Due 2027	60.0		60.0
3.30% Series Due 2028	40.0		—
5.69% Series Due 2036	50.0		50.0
6.00% Series Due 2040	35.0		35.0
5.82% Series Due 2040	45.0		45.0
4.08% Series Due 2042	85.0		85.0
4.21% Series Due 2043	60.0		—
SWL&P First Mortgage Bonds 7.25% Series Due 2013	—		10.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		—
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 2020	24.6		27.5
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025	27.8		27.8
Unsecured Term Loan Variable Rate Due 2015	75.0		75.0
Other Long-Term Debt, 0.15% – 7.50% Due 2014 – 2037	41.8		41.8
Total Long-Term Debt	1,110.2		1,018.1
Less: Due Within One Year	27.2		84.5
Net Long-Term Debt		$1,083.0		$933.6

On December 10, 2013, we agreed to sell $215.0 million in 2014 of ALLETE First Mortgage Bonds (Bonds) in the private placement market in four series as follows:



Issue Date (on or about)	Maturity Date	Principal Amount	Interest Rate
March 4, 2014	March 15, 2024	$60 Million	3.69%
March 4, 2014	March 15, 2044	$40 Million	4.95%
June 26, 2014	July 15, 2022	$75 Million	3.40%
June 26, 2014	July 15, 2044	$40 Million	5.05%

- Definition

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

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

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

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-Name Accounting Standards Codification

-Topic 835

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

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-Name Accounting Standards Codification

-Topic 505

-SubTopic 10

-Section 50

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 02

-Paragraph 22

-Article 5

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 210

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.5-02.22)

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-Name Accounting Standards Codification

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-Topic 942

-SubTopic 470

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-Paragraph 3

-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

+ Details

Common Stock and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Common Stock and Earnings Per Share [Abstract]

Summary of Common Stock [Table Text Block]



Summary of Common Stock	Shares	Equity
	Thousands	Millions
Balance as of December 31, 2010	35,817		$636.1
Employee Stock Purchase Program	20	0.8
Invest Direct	437	17.2
Options and Stock Awards	109	6.7
Equity Issuance Program	400	16.0
Purchase of Non-Controlling Interest	222	8.8
Contributions to Pension	508	20.0
Balance as of December 31, 2011	37,513		$705.6
Employee Stock Purchase Program	20	0.8
Invest Direct	474	19.2
Options and Stock Awards	95	6.0
Equity Issuance Program	1,275	53.1
Balance as of December 31, 2012	39,377		$784.7
Employee Stock Purchase Program	16	0.7
Invest Direct	395	18.5
Options and Stock Awards	301	17.9
Equity Issuance Program	1,312	63.4
Balance as of December 31, 2013	41,401		$885.2

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



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2013
Net Income Attributable to ALLETE		$104.7			$104.7
Average Common Shares	39.7		0.1	39.8
Earnings Per Share		$2.64			$2.63
2012
Net Income Attributable to ALLETE		$97.1			$97.1
Average Common Shares	37.6		—	37.6
Earnings Per Share		$2.59			$2.58
2011
Net Income Attributable to ALLETE		$93.8			$93.8
Average Common Shares	35.3		0.1	35.4
Earnings Per Share		$2.66			$2.65

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2013			2012			2011
Millions
Current Tax Expense (Benefit)
Federal (a)	—			—			$1.4
State (a)	$0.1			$0.5			(1.6		)
Total Current Tax Expense (Benefit)	0.1			0.5			(0.2		)
Deferred Tax Expense
Federal (b)	22.9			37.0			27.4
State (b)	6.5			1.4			9.3
Investment Tax Credit Amortization	(0.8		)	(0.9		)	(0.9		)
Total Deferred Tax Expense	28.6			37.5			35.8
Total Income Tax Expense		$28.7			$38.0			$35.6

(a)

(b)

Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Table Text Block]



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2013			2012			2011
Millions
Income Before Non-Controlling Interest and Income Taxes		$133.4			$135.1			$129.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$46.7			$47.3			$45.2
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	4.3			1.2			6.0
Deferred Accounting for Retail Portion of the PPACA	—			—			(2.9		)
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal	—			—			(6.2		)
Regulatory Differences for Utility Plant	(2.2		)	(2.2		)	(1.2		)
Production Tax Credits	(19.2		)	(7.6		)	(4.3		)
Other	(0.9		)	(0.7		)	(1.0		)
Total Income Tax Expense		$28.7			$38.0			$35.6

Deferred Tax Assets and Liabilities [Table Text Block]



Deferred Tax Assets and Liabilities
As of December 31	2013			2012
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$66.3			$120.2
Property Related	82.2			59.8
NOL Carryforwards	112.8			90.8
Tax Credit Carryforwards	55.1			28.3
Other	16.9			24.6
Gross Deferred Tax Assets	333.3			323.7
Deferred Tax Asset Valuation Allowance	(8.0		)	(2.4		)
Total Deferred Tax Assets		$325.3			$321.3
Deferred Tax Liabilities
Property Related		$656.2			$577.1
Regulatory Asset for Benefit Obligations	58.7			104.3
Unamortized Investment Tax Credits	11.1			11.9
Partnership Basis Differences	36.7			28.6
Other	22.7			30.1
Total Deferred Tax Liabilities		$785.4			$752.0
Net Deferred Income Taxes		$460.1			$430.7
Recorded as:
Net Current Deferred Tax Assets (a)		$19.0		—
Net Current Deferred Tax Liabilities (b)	—				$6.9
Net Long-Term Deferred Tax Liabilities	479.1			423.8
Net Deferred Income Taxes		$460.1			$430.7


(a)	In 2013, Current Deferred Tax Assets reflect the expectation of using federal NOL carryforward deductions in 2014.


(b)	Included in Other Current Assets and Other Current Liabilities.

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
Year Ended December 31	2013	2012
Millions
Federal NOL Carryforwards (a)	$279.8		$244.1
Federal Tax Credit Carryforwards	$35.5	$16.0
State NOL Carryforwards (a)	$156.3	$90.6
State Tax Credit Carryforwards (b)	$11.9	$10.3


(a)	Pretax amounts


(b)	Net of $7.7 million valuation allowance.

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2013			2012			2011
Millions
Balance at January 1		$2.7			$11.4			$12.3
Additions for Tax Positions Related to the Current Year	0.1			—			—
Additions for Tax Positions Related to Prior Years	1.3			—			—
Reductions for Tax Positions Related to Prior Years	—			(8.7		)	(0.9		)
Reductions for Settlements	(2.9		)	—			—
Balance as of December 31		$1.2			$2.7			$11.4

- Definition

Tabular disclosure of tax positions taken in the tax returns filed or to be filed for which it is more likely than not that the tax position will not be sustained upon examination by taxing authorities (i.e., uncertain tax positions) and other types of income tax contingencies, including: (1) the policy on classification of interest and penalties; (2) a tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period; the total amount(s) of: (3) unrecognized tax benefits that, if recognized, would affect the effective tax rate, and (4) interest and penalties recognized in each of the income statement and balance sheet; (5) for positions for which it is reasonably possible that the total amounts unrecognized will significantly change within 12 months of the reporting date the: (i) nature of the uncertainty, (ii) nature of the event that could occur that would cause the change, and (iii) an estimate of the range of the reasonably possible change or a statement that an estimate of the range cannot be made; and (6) a description of tax years that remain subject to examination by major tax jurisdictions.

+ References+ Details

Reclassifications Out of Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2013

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

Changes in Accumulated Other Comprehensive Loss [Table Text Block]

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2013, were as follows:



	Unrealized Gains and Losses on Available-for-sale Securities		Defined Benefit Pension, Other Postretirement Items	Gains and Losses on Cash Flow Hedge	Total
Millions
For the Year Ended December 31, 2013
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(21.5)	$(0.4)	$(22.0)
Other Comprehensive Income Before Reclassifications	1.3		3.2	0.1	4.6
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	(1.3	)	1.6	—	0.3
Net Other Comprehensive Income	—		4.8	0.1	4.9
Ending Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)	$(0.3)	$(17.1)

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

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2013, were as follows:



	Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	December 31,
	2013
Millions
Unrealized Gains on Available-for-sale Securities (a)	$2.2
Income Taxes (b)	(0.9	)
Total, Net of Income Taxes	$1.3

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.8
Actuarial Gains and Losses (c)	(3.5	)
Total	(2.7	)
Income Taxes (b)	1.1
Total, Net of Income Taxes	$(1.6)
Total Reclassifications	$(0.3)


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


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


(c)	Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense (See Note 17. Pension and Other Postretirement Benefit Plans).

Pension and Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments
	Pension		Postretirement Health and Life
Millions
2014		$33.9		$7.7
2015		$34.9		$8.4
2016		$35.8		$8.8
2017		$36.9		$9.2
2018		$37.8		$9.4
Years 2019 – 2023		$200.2		$50.6

Defined Benefit Costs Recorded in Regulatory Long-Term Assets or Liabilities and Accumulated Other Comprehensive Income Expected to be Recognized over Next Fiscal Year [Table Text Block]



	Pension		Postretirement Health and Life
Millions
Net Loss		$14.2		$0.5
Prior Service Cost (Credit)	0.3		(2.5		)
Total Pension and Postretirement Health and Life Cost (Credit)		$14.5	$(2.0)

Weighted-Average Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs [Table Text Block]



Weighted-Average Assumptions Used to Determine Benefit Obligation
As of December 31	2013	2012
Discount Rate
Pension	4.93%	4.10%
Postretirement Health and Life	4.96%	4.13%
Rate of Compensation Increase	3.7 - 4.3%	4.3 - 4.6%
Health Care Trend Rates
Trend Rate	7.25%	9.25%
Ultimate Trend Rate	5%	5%
Year Ultimate Trend Rate Effective	2020	2019



Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2013	2012	2011
Discount Rate	4.10 - 4.13%	4.54 - 4.56%	5.36 - 5.40%
Expected Long-Term Return on Plan Assets (a)
Pension	8.25%	8.25%	8.5%
Postretirement Health and Life	6.6 - 8.25%	6.6 - 8.25%	6.8 - 8.5%
Rate of Compensation Increase	4.3 - 4.6%	4.3 - 4.6%	4.3 - 4.6%


(a)	The expected long-term rate of return used to determine net periodic benefit expense for 2014 has been reduced to 8.00 percent.

Plan Asset Allocations, Actual and Target [Table Text Block]



Actual Plan Asset Allocations
	Pension				Postretirement Health and Life (a)
	2013		2012		2013		2012
Equity Securities	52	%	54	%	63	%	56	%
Debt Securities	34	%	28	%	29	%	35	%
Private Equity	9	%	13	%	8	%	9	%
Real Estate	5	%	5	%	—		—
	100	%	100	%	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.



Plan Asset Target Allocations
	Pension		Postretirement Health and Life (a)
Equity Securities	52	%	50	%
Debt Securities	30	%	30	%
Private Equity	9	%	10	%
Real Estate	9	%	10	%
	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments
Available-for-sale Securities – Equity Securities		$7.9	—		—		$7.9
Available-for-sale Securities – Corporate Debt Securities	—			$9.8	—	9.8
Cash Equivalents	34.2		—		—	34.2
Total Fair Value of Assets		$42.1		$9.8	—		$51.9

Liabilities:
Deferred Compensation	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap	—		0.6		—	0.6
Total Fair Value of Liabilities	—			$17.4	—		$17.4
Total Net Fair Value of Assets (Liabilities)		$42.1	$(7.6)		—		$34.5



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

Liabilities:
Deferred Compensation	—			$14.0	—		$14.0
Derivatives – Interest Rate Swap	—		0.7		—	0.7
Total Fair Value of Liabilities	—			$14.7	—		$14.7
Total Net Fair Value of Assets (Liabilities)		$38.7	$(5.9)		—		$32.8

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Pension Obligation and Funded Status
Year Ended December 31	2013			2012
Millions
Accumulated Benefit Obligation		$577.6			$598.7
Change in Benefit Obligation
Obligation, Beginning of Year		$652.1			$597.5
Service Cost	9.9			9.1
Interest Cost	26.0			26.4
Actuarial (Gain) Loss	(49.2		)	38.5
Benefits Paid	(33.5		)	(30.9		)
Participant Contributions	17.5			11.5
Obligation, End of Year		$622.8			$652.1
Change in Plan Assets
Fair Value, Beginning of Year		$460.1			$432.4
Actual Return on Plan Assets	56.5			38.7
Employer Contribution (a)	18.5			19.9
Benefits Paid	(33.5		)	(30.9		)
Fair Value, End of Year		$501.6			$460.1
Funded Status, End of Year	$(121.2)			$(192.0)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.1)			$(1.1)
Non-Current Liabilities	$(120.1)			$(190.9)


(a)	Includes participant contributions noted above.

Unrecognized Costs [Table Text Block]



Unrecognized Pension Costs
Year Ended December 31	2013		2012
Millions
Net Loss		$194.9		$286.8
Prior Service Cost	0.4		0.7
Total Unrecognized Pension Costs		$195.3		$287.5

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Pension Expense
Year Ended December 31	2013			2012			2011
Millions
Service Cost		$9.9			$9.1			$7.6
Interest Cost	26.0			26.4			27.4
Expected Return on Plan Assets	(35.2		)	(35.4		)	(34.6		)
Amortization of Loss	21.5			17.5			12.1
Amortization of Prior Service Cost	0.3			0.3			0.3
Net Pension Expense		$22.5			$17.9			$12.8

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets [Table Text Block]



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2013		2012
Millions
Net (Gain) Loss	$(70.4)			$35.2
Amortization of Prior Service Cost	(0.3	)	(0.3		)
Amortization of Loss	(21.5	)	(17.5		)
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(92.2)			$17.4

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets [Table Text Block]



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Year Ended December 31	2013		2012
Millions
Projected Benefit Obligation		$622.8		$652.1
Accumulated Benefit Obligation		$577.6		$598.7
Fair Value of Plan Assets		$501.6		$460.1

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$43.0		$36.0	—			$79.0
U.S. Mid-cap Growth (a)	18.3		15.3		—		33.6
U.S. Small-cap (a)	18.3		15.3		—		33.6
International	50.5		45.9		—		96.4
Debt Securities:
Mutual Funds	72.5		—		—		72.5
Fixed Income	10.4		50.8		—		61.2
Other Types of Investments:
Private Equity Funds	—		—			$58.9	58.9
Real Estate	—		—		24.9		24.9
Total Fair Value of Assets		$213.0		$163.3		$83.8		$460.1

(a)



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$20.9		$59.3	—			$80.2
U.S. Mid-cap Growth (a)	9.4		26.7		—		36.1
U.S. Small-cap (a)	9.9		28.2		—		38.1
International	61.2		43.5		—		104.7
Debt Securities:
Mutual Funds	130.1		—		—		130.1
Fixed Income	—		36.4		—		36.4
Cash Equivalents	2.7		—		—		2.7
Other Types of Investments:
Private Equity Funds	—		—			$46.8	46.8
Real Estate	—		—		26.5		26.5
Total Fair Value of Assets		$234.2		$194.1		$73.3		$501.6

(a)

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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2011		$69.0			$21.7
Actual Return on Plan Assets	(9.7		)	3.4
Purchases, sales, and settlements, net	(0.4		)	(0.2		)
Balance as of December 31, 2012		$58.9			$24.9



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2012		$58.9			$24.9
Actual Return on Plan Assets	2.3			2.1
Purchases, sales, and settlements, net	(14.4		)	(0.5		)
Balance as of December 31, 2013		$46.8			$26.5

Postretirement Health and Life [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Postretirement Health and Life Obligation and Funded Status
Year Ended December 31	2013			2012
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$168.8			$210.6
Service Cost	3.9			4.2
Interest Cost	6.8			9.4
Actuarial Gain	(18.8		)	(43.2		)
Participant Contributions	2.7			2.6
Plan Amendments	—			(5.3		)
Benefits Paid	(9.9		)	(9.5		)
Settlements (a)	(1.6		)	—
Obligation, End of Year		$151.9			$168.8
Change in Plan Assets
Fair Value, Beginning of Year		$131.0			$121.0
Actual Return on Plan Assets	21.4			14.3
Employer Contribution	11.7			2.3
Participant Contributions	2.7			2.5
Benefits Paid	(9.8		)	(9.1		)
Fair Value, End of Year		$157.0			$131.0
Funded Status, End of Year	$5.1			$(37.8)

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$19.4			—
Current Liabilities	$(0.9)			$(0.8)
Non-Current Liabilities	$(13.4)			$(37.0)


(a)	Result of the exit from a legacy benefit plan.

Unrecognized Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
Year Ended December 31	2013		2012
Millions
Net (Gain) Loss	$(9.0)			$23.5
Prior Service Credit	(10.1	)	(13.1		)
Total Unrecognized Postretirement Health and Life Costs (Credit)	$(19.1)			$10.4

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2013			2012			2011
Millions
Service Cost		$3.9			$4.2			$3.8
Interest Cost	6.8			9.4			10.8
Expected Return on Plan Assets	(9.7		)	(9.9		)	(9.7		)
Amortization of Prior Service Credit	(2.5		)	(1.7		)	(1.7		)
Amortization of Loss	1.6			7.5			8.5
Amortization of Transition Obligation	—			0.1			0.1
Effect of Plan Settlement (a)	(1.6		)	—			—
Net Postretirement Health and Life Expense (Credit)	$(1.5)				$9.6			$11.8


(a)	Result of the exit from a legacy benefit plan.

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets [Table Text Block]



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets
Year Ended December 31	2013		2012
Millions
Net Gain	$(30.2)		$(47.5)
Prior Service Credit Arising During the Period	—		(5.3	)
Amortization of Prior Service Credit	2.5		1.7
Amortization of Transition Obligation	—		(0.1	)
Amortization of Loss	(1.6	)	(7.5	)
Amount Recognized due to Plan Settlement (a)	(0.2	)	—
Total Recognized in Other Comprehensive Income and Regulatory Assets	$(29.5)		$(58.7)


(a)	Result of the exit from a legacy benefit plan.

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates [Table Text Block]



Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
	One Percent Increase		One Percent Decrease
Millions
Effect on Total of Postretirement Health and Life Service and Interest Cost		$1.6	$(1.3)
Effect on Postretirement Health and Life Obligation		$16.0	$(13.4)

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$28.3	—		—			$28.3
U.S. Mid-cap Growth (a)	17.6		—		—		17.6
U.S. Small-cap (a)	18.2		—		—		18.2
International	33.4		—		—		33.4
Debt Securities:
Mutual Funds	30.8		—		—		30.8
Fixed Income	—			$15.5	—		15.5
Cash Equivalents	0.1		—		—		0.1
Other Types of Investments:
Private Equity Funds	—		—			$13.1	13.1
Total Fair Value of Assets		$128.4		$15.5		$13.1		$157.0


(a)	The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).



	Fair Value as of December 31, 2012
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$16.7	—		—			$16.7
U.S. Mid-cap Growth (a)	13.2		—		—		13.2
U.S. Small-cap (a)	13.3		—		—		13.3
International	30.3		—		—		30.3
Debt Securities:
Mutual Funds	25.5		—		—		25.5
Fixed Income	0.2			$18.3	—		18.5
Other Types of Investments:
Private Equity Funds	—		—			$13.5	13.5
Total Fair Value of Assets		$99.2		$18.3		$13.5		$131.0


(a)	The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2011		$14.0
Actual Return on Plan Assets	0.2
Purchases, sales, and settlements, net	(0.7		)
Balance as of December 31, 2012		$13.5



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds
Millions
Balance as of December 31, 2012		$13.5
Actual Return on Plan Assets	2.4
Purchases, sales, and settlements, net	(2.8		)
Balance as of December 31, 2013		$13.1

Employee Stock and Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2013

Employee Stock and Incentive Plans [Abstract]

Employee Stock Ownership Plan [Table Text Block]



Year Ended December 31	2013		2012		2011
Millions
ESOP Shares
Allocated	2.0		2.2		2.2
Unallocated	0.5		0.7		1.0
Total	2.5		2.9		3.2
Fair Value of Unallocated Shares		$24.1		$28.7		$42.0

Share-Based Compensation Expense [Table Text Block]

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	2013		2012		2011
Millions
Performance Shares		$1.7		$1.4		$1.1
Restricted Stock Units	0.7		0.7		0.5
Total Share-Based Compensation Expense		$2.4		$2.1		$1.6
Income Tax Benefit		$1.0		$0.9		$0.7

Non-Qualified Stock Options [Table Text Block]

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2013.



	2013			2012			2011
	Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price		Number of Options	Weighted-Average Exercise Price
Outstanding as of January 1,	395,678		$42.28	460,234		$41.68	560,887		$40.69
Granted (a)	—	—		—	—		—	—
Exercised	287,379		$41.60	49,075		$35.84	80,798		$34.25
Forfeited	—	—		15,481		$44.86	19,855		$43.96
Outstanding as of December 31,	108,299		$44.10	395,678		$42.28	460,234		$41.68
Exercisable as of December 31,	108,299		$43.17	395,678		$41.71	460,234		$41.59


(a)	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Stock Options, by Exercise Price Range [Table Text Block]



	Range of Exercise Price
As of December 31, 2013	$37.76 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	44,263		64,036
Weighted Average Remaining Contractual Life (Years)	2.6		2.7
Weighted Average Exercise Price		$40.18		$46.81

Performance Shares [Table Text Block]

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2013.



	2013				2012				2011
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Non-vested as of January 1,	107,899			$40.73	128,333			$36.54	122,489			$38.15
Granted (a)	45,830			$52.15	38,764			$44.70	39,312			$41.00
Awarded	(18,605	)		$35.10	(41,009	)		$34.25	(32,368	)		$48.10
Unearned Grant Award	(18,606	)		$35.10	(17,575	)		$34.25	—		—
Forfeited	(1,753	)		$47.26	(614	)		$34.49	(1,100	)		$34.35
Non-vested as of December 31,	114,765			$47.02	107,899			$40.73	128,333			$36.54

(a) Shares granted includes accrued dividends.

Restricted Stock Units [Table Text Block]

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2013.



	2013				2012				2011
	Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value		Number of Shares		Weighted- Average Grant Date Fair Value
Available as of January 1,	56,415			$36.61	63,464			$32.57	43,803			$30.61
Granted (a)	21,440			$43.41	18,162			$40.83	20,136			$36.74
Awarded	(20,939	)		$32.03	(24,707	)		$29.43	(215	)		$30.30
Forfeited	(934	)		$41.02	(504	)		$31.80	(260	)		$29.41
Available as of December 31,	55,982			$40.85	56,415			$36.61	63,464			$32.57

(a) Shares granted includes accrued dividends.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited) [Table Text Block]



Quarter Ended	Mar. 31		Jun. 30		Sept. 30		Dec. 31
Millions Except Earnings Per Share
2013
Operating Revenue		$263.8		$235.6		$251.0		$268.0
Operating Income		$44.4		$24.4		$38.4		$46.9
Net Income Attributable to ALLETE		$32.5		$14.0		$25.2		$33.0
Earnings Per Share of Common Stock
Basic		$0.83		$0.36		$0.63		$0.82
Diluted		$0.83		$0.35		$0.63		$0.82
2012
Operating Revenue		$240.0		$216.4		$248.8		$256.0
Operating Income		$38.4		$23.3		$45.6		$47.9
Net Income Attributable to ALLETE		$24.4		$14.4		$29.4		$28.9
Earnings Per Share of Common Stock
Basic		$0.66		$0.39		$0.78		$0.76
Diluted		$0.66		$0.39		$0.78		$0.75

Operations and Significant Accounting Policies (Details) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified

3 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Customer Information [Line Items]

Escrow Deposit

$ 5.4

Non-Controlling Interest in Subsidiaries [Abstract]

Purchase of Non-Controlling Interest at Book Value

8.8

Purchase of Non-Controlling Interest, Shares Issued

200

Trade Accounts Receivable [Abstract]

Billed

78.7

70.4

Unbilled

18.7

17.4

Less: Allowance for Doubtful Accounts

1.1

1.0

Total Trade Accounts Receivable

96.3

86.8

Income Taxes Receivable

2.2

Total Accounts Receivable - Net

96.3

89.0

Inventories [Abstract]

Fuel

13.1

^[1]

28.0

^[1]

Materials and Supplies

46.2

41.8

Total Inventories

59.3

69.8

Impairement of Long-Lived Assets [Abstract]

Land Impairment

1.7

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

23.0

22.5

Other

12.1

11.1

Total Prepayments and Other Current Assets

35.1

33.6

Other Current Liabilities [Abstract]

Customer Deposits

26.0

28.8

Other

26.6

33.8

Total Other Current Liabilities

52.6

62.6

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

81.8

77.9

57.0

Other

45.4

Total Other Non-Current Liabilities

$ 127.2

$ 123.3

Income Tax Disclosure [Abstract]

More Likely Than Not Definition

50.00%

Municipal Customers [Member]

Customer Information [Line Items]

Number of Customers

Non-Affiliated Private Utility [Member]

Customer Information [Line Items]

Number of Customers

Retail Customers [Member]

Customer Information [Line Items]

Number of Customers

143,000

Electric [Member]

Customer Information [Line Items]

Number of Customers

15,000

Natural Gas [Member]

Customer Information [Line Items]

Number of Customers

12,000

Water [Member]

Customer Information [Line Items]

Number of Customers

10,000

[1]	Fuel inventory was lower in 2013 primarily due to higher than expected thermal generation and the timing of coal shipments.

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Supplemental Cash Flow Information [Abstract]

Cash Paid During the Period for Interest - Net of Amounts Capitalized

$ 47.5

$ 42.7

$ 43.2

Cash Paid (Received) During the Period for Income Taxes

0.5

^[1]

(11.4)

^[1]

Noncash Investing and Financing Activities [Abstract]

Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment

8.3

20.2

5.9

Increase (Decrease) in Capitalized Asset Retirement Costs

(0.7)

17.1

0.3

AFUDC - Equity

4.6

5.1

2.5

ALLETE Common Stock Contributed to Pension Plan

$ 0

$ (20.0)

[1]	Due to bonus depreciation provisions in 2010 and 2012 federal legislation, NOLs were generated which resulted in little or no estimated tax payments, and in 2011, refunds were received from NOL carrybacks against prior years’ taxable income.

Operations and Significant Accounting Policies - Investments and Other (Details)	12 Months Ended
	Dec. 31, 2013
Long-term Contract for Purchase of Electric Power [Line Items]
Real Estate Sales Revenue Recognition, Minimum Contract Price Cash Collections Requirement (Percent)	20.00%
Square Butte PPA [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Output Purchased (MW)	227.5
Square Butte Coal-fired Unit [Member] \| Square Butte PPA [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Output Purchased (Percent)	50.00%

Operations and Significant Accounting Policies - Concentraion of Credit Risk (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Customer Information [Line Items]
Major Customer, Percent of Total Revenue	12.00%	12.30%	12.60%
Large Power Customer [Member]
Customer Information [Line Items]
Number of Customers	9
Large Power Customers, Accounts Receivable	$ 14.2	$ 13.7

Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Segments [Line Items]
Operating Revenue	$ 268.0	$ 251.0	$ 235.6	$ 263.8	$ 256.0	$ 248.8	$ 216.4	$ 240.0	$ 1,018.4	$ 961.2	$ 928.2
Fuel and Purchased Power Expense									334.8	308.7	306.6
Operating and Maintenance Expense									412.9	397.1	381.2
Depreciation Expense									116.6	100.2	90.4
Operating Income (Loss)	46.9	38.4	24.4	44.4	47.9	45.6	23.3	38.4	154.1	155.2	150.0
Interest Expense									(50.3)	(45.5)	(43.6)
Equity Earnings in ATC									20.3	19.4	18.4
Other Income									9.3	6.0	4.4
Income (Loss) Before Non-Controlling Interest and Income Taxes									133.4	135.1	129.2
Income Tax Expense (Benefit)									28.7	38.0	35.6
Net Income (Loss)									104.7	97.1	93.6
Less: Non-Controlling Interest in Subsidiaries									0	0	(0.2)
Net Income (Loss) Attributable to ALLETE	33.0	25.2	14.0	32.5	28.9	29.4	14.4	24.4	104.7	97.1	93.8
Total Assets	3,476.8				3,253.4				3,476.8	3,253.4	2,876.0
Capital Additions									339.5	432.2	246.8
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue									925.5	874.4	851.9
Fuel and Purchased Power Expense									334.8	308.7	306.6
Operating and Maintenance Expense									322.4	310.0	301.5
Depreciation Expense									110.2	93.9	85.4
Operating Income (Loss)									158.1	161.8	158.4
Interest Expense									(42.1)	(39.8)	(35.8)
Equity Earnings in ATC									20.3	19.4	18.4
Other Income									4.7	5.1	2.6
Income (Loss) Before Non-Controlling Interest and Income Taxes									141.0	146.5	143.6
Income Tax Expense (Benefit)									36.1	50.4	43.2
Net Income (Loss)									104.9	96.1	100.4
Less: Non-Controlling Interest in Subsidiaries											0
Net Income (Loss) Attributable to ALLETE											100.4
Total Assets	3,160.8				2,962.4				3,160.8	2,962.4	2,579.8
Capital Additions									326.3	418.2	228.0
Investments and Other [Member]
Business Segments [Line Items]
Number of acres of land in Minnesota (in acres)	5,000								5,000
Operating Revenue									92.9	86.8	76.3
Fuel and Purchased Power Expense									0	0	0
Operating and Maintenance Expense									90.5	87.1	79.7
Depreciation Expense									6.4	6.3	5.0
Operating Income (Loss)									(4.0)	(6.6)	(8.4)
Interest Expense									(8.2)	(5.7)	(7.8)
Equity Earnings in ATC									0	0	0
Other Income									4.6	0.9	1.8
Income (Loss) Before Non-Controlling Interest and Income Taxes									(7.6)	(11.4)	(14.4)
Income Tax Expense (Benefit)									(7.4)	(12.4)	(7.6)
Net Income (Loss)									(0.2)	1.0	(6.8)
Less: Non-Controlling Interest in Subsidiaries											(0.2)
Net Income (Loss) Attributable to ALLETE											(6.6)
Total Assets	316.0				291.0				316.0	291.0	296.2
Capital Additions									$ 13.2	$ 14.0	$ 18.8

Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment - Net	$ 2,576.5	$ 2,347.6
Asset Retirement Obligation [Roll Forward]
Beginning Obligation	77.9	57.0
Accretion Expense	4.6	3.8
Revisions in estimated cash flows	(0.7)	17.1
Ending Obligation	81.8	77.9
Regulated Utiity [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	3,380.0	3,232.9
Construction Work in Progress	303.9	151.8
Accumulated Depreciation	(1,181.7)	(1,102.8)
Property, Plant and Equipment - Net	2,502.2	2,281.9
Regulated Utiity [Member] \| Generation Plant [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	5 to 35 years
Regulated Utiity [Member] \| Transmission [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	42 to 61 years
Regulated Utiity [Member] \| Distribution [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	14 to 65 years
Non-Rate Base Energy Operations and Other Plant [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	131.3	118.0
Construction Work in Progress	3.4	4.2
Accumulated Depreciation	(60.4)	(56.7)
Property, Plant and Equipment - Net	74.3	65.5
Other Plant - Net	$ 0	$ 0.2
Non-Rate Base Energy Operations and Other Plant [Member] \| Other Plant [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	5 to 25 years

Jointly-Owned Facilities and Projects (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 438.9
Accumulated Depreciation	198.5
Construction Work in Progress	129.2
Boswell Unit 4 [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	80.00%
Generating Capacity (MW)	585
% Not Owned	20.00%
Plant in Service	416.1
Accumulated Depreciation	197.5
Construction Work in Progress	71.5
CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	3
Plant in Service	22.8
Accumulated Depreciation	1.0
Construction Work in Progress	$ 57.7
CapX2020 Projects [Member] \| Minimum [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	9.30%
CapX2020 Projects [Member] \| Maximum [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	14.70%

Regulatory Matters - Utility Rates (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 Bison Wind Energy Center [Member] MW	Dec. 31, 2013 Bison 4 Wind Project [Member] MW	Dec. 31, 2013 Municipal Customers [Member] Customers	Dec. 31, 2013 Non-Affiliated Private Utility [Member] Customers	Jun. 01, 2011 MPUC 2010 MN Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Dec. 31, 2013 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Years Customers	Dec. 31, 2013 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Non-Affiliated Private Utility [Member] Customers MW	Dec. 31, 2012 PSCW 2012 Wisconsin Rate Case [Member] Retail Customers [Member]
Rate Regulation [Line Items]
Approved Rate of Return on Common Equity					10.38%			10.90%
Approved Percentage of Capital Structure Related to Equity					54.29%
Number of Customers			16	1		16	1
Average Monthly Demand (in MWs)							17
Length of Notice Required to Terminate (Years)						3
Generating Capacity (MW)	292	205
Estimated Capital Expenditures		$ 345
Capital Cost Spent to Date		$ 55.6

Regulatory Matters - The Patient Protection and Affordable Care Act of 2010 (PPACA) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Benefit		$ 28.6	$ 37.5	$ 35.8
Non-Current Regulatory Asset		263.8	340.3
PPACA Elimination of Medicare Part D [Member]
Unusual or Infrequent Item [Line Items]
Reversal of Previously Recorded Tax Benefit					4.0
Deferred Income Tax Benefit	2.9	0	0	(2.9)
Non-Current Regulatory Asset	$ 5.0

- Definition

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

+ References+ Details

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

Dec. 31, 2013

Dec. 31, 2012

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Asset

$ 23.0

$ 22.5

Non-Current Regulatory Asset

263.8

340.3

Total Regulatory Assets

286.8

362.8

Non-Current Regulatory Liability

81.0

60.1

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

17.0

19.5

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

19.7

18.1

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

19.7

15.5

Defined Benefit Pension and Other Postretirement Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

16.3

^[1]

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

8.3

7.0

Deferred Fuel [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Asset

23.0

^[2]

22.5

^[2]

Defined Benefit Pension and Other Postretirement Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

164.1

^[1]

260.7

^[1]

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

35.3

36.0

Asset Retirement Obligation [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

16.0

12.1

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

39.6

^[3]

18.5

^[3]

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

5.0

Conservation Improvement Program [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

4.3

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

$ 3.8

$ 3.7

[1]	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, are recognized as regulatory assets or regulatory liabilities on our Consolidated Balance Sheet (See Note 17. Pension and Other Postretirement Benefit Plans).
[2]	Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
[3]	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Balance Sheet Data [Abstract]
Current Assets		$ 80.7	$ 63.1
Non-Current Assets		3,509.5	3,274.7
Total Assets		3,590.2	3,337.8
Current Liabilities		381.4	251.5
Long-Term Debt		1,550.0	1,550.0
Other Non-Current Liabilities		126.2	95.8
Members' Equity		1,532.6	1,440.5
Total Liabilities and Members' Equity		3,590.2	3,337.8
Income Statement Data [Abstract]
Revenue		626.3	603.2	567.2
Operating Expense		295.1	281.0	261.6
Other Expense		83.6	84.8	81.7
Net Income		247.6	237.4	223.9
ALLETE's Equity in Net Income		20.3	19.4	18.4
Investment in ATC [Abstract]
Equity Method Investment, Ownership Percentage		8.00%
Equity Method Investment, Approved Return on Common Equity		12.20%
Equity Method Investment, Total Expected Investment for Current Year		5.8
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance	114.6	107.3	98.9
Cash Investments	1.2	3.1	4.7
Equity Earnings in ATC		20.3	19.4	18.4
Distributed ATC Earnings		(16.1)	(15.7)
Equity Investment Ending Balance		$ 114.6	$ 107.3	$ 98.9

Acquisitions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Jan. 30, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Business Acquisition, Effective Date of Acquisition	Jan. 30, 2014
Business Acquisition, Transaction Costs		$ 27.0
Escrow Deposit Disbursements Related to Property Acquisition			$ 5.4
Lake Benton [Member]
Business Acquisition [Line Items]
Business Acquisition, Name of Acquired Entity	Lake Benton
Generating Capacity (MW)		104
Storm Lake [Member]
Business Acquisition [Line Items]
Business Acquisition, Name of Acquired Entity	Storm Lake
Generating Capacity (MW)		77
Condon [Member]
Business Acquisition [Line Items]
Business Acquisition, Name of Acquired Entity	Condon
Generating Capacity (MW)		50

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Available-for-sale Securities [Abstract]

Cost

$ 18.3

$ 27.4

$ 27.3

Gross Unrealized Gain

0.5

0.1

Gross Unrealized (Loss)

(0.6)

(1.1)

(2.7)

Fair Value

17.7

26.8

24.7

Net Proceeds

16.1

1.5

7.8

Gross Realized Gain

2.2

Gross Realized (Loss)

Net Unrealized Gain (Loss) in Other Comprehensive Income

1.2

(0.3)

Investments [Abstract]

ALLETE Properties

89.9

91.1

Available-for-sale Securities

17.7

^[1]

26.8

^[1]

Cash Equivalents

34.2

20.7

Other

4.5

4.9

Total Other Investments

146.3

143.5

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

0.6

Available-for-sale Securities, Debt Maturities, One Year to Less Than Three Years

4.7

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

2.0

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

2.5

ALLETE Properties [Roll Forward]

Land Inventory Beginning Balance

86.5

86.0

Cost of Sales

(1.5)

(0.2)

Other

0.4

0.7

Land Inventory Ending Balance

85.4

86.5

86.0

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

1.4

Other

3.1

3.2

Total Real Estate Assets

89.9

91.1

Land Impairment

Long-Term Finance Receivables, Allowance

$ 0.6

[1]	As of December 31, 2013, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.6 million, in one year to less than three years was $4.7 million, in three years to less than five years was $2.0 million, and in five or more years was $2.5 million.

Derivatives (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Interest Rate Swap [Member]
Derivative [Line Items]
Interest Rate Swap Variable Rate Basis	one-month LIBOR
Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessments of hedge effectiveness resulted in no ineffectiveness recorded for the year ended December 31, 2013.
Interest Rate Swap Liability	$ 0.6	$ 0.7
Interest Rate Swap Liability, Other Non-Current Liabilities	0.3	0.7
Interest Rate Swap Liability, Other Current Liabilities	$ 0.3	$ 0
Interest Rate Swap Effective August 25, 2011 [Member]
Derivative [Line Items]
Interest Rate Swap Fixed Interest Rate	0.825%
Interest Rate Swap Effective August 26, 2014 [Member]
Derivative [Line Items]
Interest Rate Swap Fixed Interest Rate	0.75%

Fair Value - Recurring Fair Value Measures (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Investments [Abstract]
Cash Equivalents	$ 34.2	$ 20.7
Liabilities [Abstract]
Fair Value Activity in Level 3	0	0
Fair Value Hierarchy Transfers, All Levels	0	0
Recurring Fair Value Measures [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	7.9	18.0
Available-for-sale Securities - Corporate Debt Securities	9.8	8.8
Cash Equivalents	34.2	20.7
Total Fair Value of Assets	51.9	47.5
Liabilities [Abstract]
Deferred Compensation	16.8	14.0
Derivatives - Interest Rate Swap	0.6	0.7
Total Fair Value of Liabilities	17.4	14.7
Total Net Fair Value of Assets (Liabilities)	34.5	32.8
Recurring Fair Value Measures [Member] \| Level 1 [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	7.9	18.0
Available-for-sale Securities - Corporate Debt Securities	0	0
Cash Equivalents	34.2	20.7
Total Fair Value of Assets	42.1	38.7
Liabilities [Abstract]
Deferred Compensation	0	0
Derivatives - Interest Rate Swap	0	0
Total Fair Value of Liabilities	0	0
Total Net Fair Value of Assets (Liabilities)	42.1	38.7
Recurring Fair Value Measures [Member] \| Level 2 [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	0	0
Available-for-sale Securities - Corporate Debt Securities	9.8	8.8
Cash Equivalents	0	0
Total Fair Value of Assets	9.8	8.8
Liabilities [Abstract]
Deferred Compensation	16.8	14.0
Derivatives - Interest Rate Swap	0.6	0.7
Total Fair Value of Liabilities	17.4	14.7
Total Net Fair Value of Assets (Liabilities)	(7.6)	(5.9)
Recurring Fair Value Measures [Member] \| Level 3 [Member]
Investments [Abstract]
Available-for-sale Securities - Equity Securities	0	0
Available-for-sale Securities - Corporate Debt Securities	0	0
Cash Equivalents	0	0
Total Fair Value of Assets	0	0
Liabilities [Abstract]
Deferred Compensation	0	0
Derivatives - Interest Rate Swap	0	0
Total Fair Value of Liabilities	0	0
Total Net Fair Value of Assets (Liabilities)	$ 0	$ 0

Fair Value - Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,110.2	$ 1,018.1
Long-Term Debt, Including Current Portion - Fair Value	$ 1,131.7	$ 1,143.7

- Definition

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

+ References+ Details

Short-Term and Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended		3 Months Ended								0 Months Ended						0 Months Ended
	Dec. 10, 2013	Apr. 02, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Lines of Credit [Member]	Dec. 31, 2012 Lines of Credit [Member]	Nov. 04, 2013 ALLETE LOC Nov2018 [Member] [Member]	Nov. 04, 2013 ALLETE LOC June 2015 [Member]	Nov. 04, 2013 ALLETE LOC January 2014 [Member]	Dec. 31, 2012 ALLETE Bonds 4.86% Due 2013 [Member]	Apr. 02, 2013 ALLETE Bonds 1.83% Due April2018 [Member]	Apr. 02, 2013 ALLETE Bonds 3.30% Due October2028 [Member]	Apr. 02, 2013 ALLETE Bonds 4.21% Due October2043 [Member]	Aug. 26, 2013 ALLETE Amended Term Loan Variable Rate Due August 2015 [Member]	Aug. 26, 2013 ALLETE Amended Term Loan Variable Rate Due 2015 Effective August 25, 2013 [Member]	Aug. 26, 2013 ALLETE Amended Term Loan Variable Rate Due 2015 Effective August 26, 2014 [Member]	Dec. 10, 2013 ALLETE Bonds 3.69% Due March2024 [Member]	Dec. 10, 2013 ALLETE Bonds 4.95% Due March2044 [Member]	Dec. 10, 2013 ALLETE Bonds 3.40% Due July2022 [Member]	Dec. 10, 2013 ALLETE Bonds 5.05% Due July2044 [Member]
Financial Covenants [Abstract]
Required Indebtedness to Total Capital Ratio			0.65
Actual Indebtedness to Total Capital Ratio			0.45
Maturities of Long-term Debt [Abstract]
Long-Term Debt			$ 1,083.0	$ 933.6
Long-Term Debt Due Within One Year			27.2	84.5						60.0
Long-Term Debt, 2014 Maturities			143.0
Long-Term Debt, 2015 Maturities			22.3
Long-Term Debt, 2016 Maturities			51.8
Long-Term Debt, 2017 Maturities			1.7
Long-Term Debt, Thereafter Maturities			864.2
Debt Instrument [Line Items]
Short-Term Debt			27.2	84.5
Line of Credit Facility, Maximum Borrowing Capacity					406.4	406.4	400.0	250.0	150.0
Line of Credit Facility Additional Borrowing Capacity							150.0
Letter of Credit Maximum Issuances							60.0
Lines of Credit, Current			5.4	0
Proceeds from Issuance of First Mortgage Bond		150.0									50.0	40.0	60.0
First Mortgage Bonds, Interest Rate											1.83%	3.30%	4.21%
Expected Proceeds from Future Issuance of First Mortgage Bond	215.0																60.0	40.0	75.0	40.0
First Mortgage Bonds, Interest Rate, Future Issuance																	3.69%	4.95%	3.40%	5.05%
Debt Instrument, Face Amount														$ 75.0
Debt Instrument, Description of Variable Rate Basis														one-month LIBOR
Debt Instrument, Basis Spread on Variable Rate														0.875%
Debt Instrument, Interest Rate, Effective Percentage															1.70%	1.625%

Short-term and Long-term Debt - Schedule of Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Total Long-term Debt	$ 1,110.2	$ 1,018.1
Less: Due Within One Year	27.2	84.5
Net Long-Term Debt	1,083.0	933.6
4.86% Series Due 2013 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	0	60.0
Less: Due Within One Year		60.0
6.94% Series Due 2014 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	18.0	18.0
1.83% Series Due 2018 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	50.0	0
7.70% Series Due 2016 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	20.0	20.0
8.17% Series Due 2019 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	42.0	42.0
5.28% Series Due 2020 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	35.0	35.0
4.85% Series Due 2021 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	15.0	15.0
4.95% Pollution Control Series F Due 2022 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	111.0	111.0
6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	75.0	75.0
4.90% Series Due 2025 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	30.0	30.0
5.10% Series Due 2025 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	30.0	30.0
3.20% Series Due 2026 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	75.0	75.0
5.99% Series Due 2027 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	60.0	60.0
3.30% Series Due 2028 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	40.0	0
5.69% Series Due 2036 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	50.0	50.0
6.00% Series Due 2040 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	35.0	35.0
5.82% Series Due 2040 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	45.0	45.0
4.08% Series Due 2042 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	85.0	85.0
4.21% Series Due 2043 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	60.0	0
SWL&P First Mortgage Bonds 7.25% Series Due 2013 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	0	10.0
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	15.0	0
Senior Unsecured Notes 5.99% Due 2017 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	50.0	50.0
Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013-2020 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	24.6	27.5
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	27.8	27.8
Unsecured Term Loan Variable Rate Due 2015 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	75.0	75.0
Other Long-Term Debt, 0.15%-7.50% Due 2014-2037 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	$ 41.8	$ 41.8

- Definition

+ References+ Details

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Debt Outstanding	$ 403.3
Annual Debt Service	44
Power Purchased under Long-term Contracts	71.1	67.1	61.2
Interest Expense	10.5	11.1	11.1
Square Butte PPA [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)	455
Output Entitlement	50.00%
Minnkota PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Oliver Wind I PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Term of Contract (Years)	25
Fixed Capacity Charges	0
Oliver Wind II PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	48
Term of Contract (Years)	25
Fixed Capacity Charges	$ 0
Manitoba Hydro PPA (expires May 2015) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50
Manitoba Hydro PPA (expires April 2022) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MWh)	1,000,000
Manitoba Hydro PPA (expires 2035) [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	250
Term of Contract (Years)	15

Commitments, Guarantees and Contingencies - North Dakota Wind Development (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 DC Transmission Line from Square Butte [Member] kV Miles	Dec. 31, 2013 Bison Wind Energy Center [Member] MW	Dec. 31, 2013 Bison 4 Wind Project [Member] MW
North Dakota Wind Development [Line Items]
Transmission Line Length (Miles)	465
Transmission Line Capacity (kV)	250
Generating Unit Capacity (MW)		292	205
Estimated Capital Expenditures			$ 345
Capital Cost Spent to Date			55.6
Minimum Payment Obligation in 2014			$ 244.4

Commitments, Guarantees and Contingencies - Hydro Operations (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Forebay Rebuild [Member]
Hydro Operations [Line Items]
Estimated Capital Expenditures	$ 25
Minimum Payment Obligation in 2014	6.7
Restoration and Upgrade Work [Member]
Hydro Operations [Line Items]
Estimated Capital Expenditures	40
Additional Hydro Work [Member]
Hydro Operations [Line Items]
Estimated Capital Expenditures	$ 15

Commitments, Guarantees and Contingencies - Coal Rail and Shipping Contracts (Details) (Coal and Transportation [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Coal and Transportation [Member]
Coal Rail and Shipping Contracts [Line Items]
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2014	$ 35.3
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2015	$ 2.2

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leasing Agreements [Line Items]
Operating Leases, Future Minimum Payments, Current	$ 12.1
Operating Leases, Future Minimum Payments, Due in Two Years	11.5
Operating Leases, Future Minimum Payments, Due in Three Years	9.5
Operating Leases, Future Minimum Payments, Due in Four Years	8.7
Operating Leases, Future Minimum Payments, Due in Five Years	7.4
Operating Leases, Future Minimum Payments, Due Thereafter	29.2
Operating Leases, Rent Expense	13.8	11.5	9.4
BNI Dragline [Member]
Leasing Agreements [Line Items]
Termination Fee	3.0
Operating Leases, Future Minimum Payments, Current	$ 2.8

Commitments, Guarantees and Contingencies - Transmission (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CapX2020 [Member]
Transmission [Line Items]
Number of Projects	3
Capital Cost Spent to Date	$ 80.5	$ 48.2
CapX2020 [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	100
CapX2020 [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	110
CapX2020 Fargo to Monticello Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	238
Transmission Line Capacity (kV)	345
Capital Cost Spent to Date	69.6	37.3
CapX2020 Monticello to St. Cloud Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	28
Transmission Line Capacity (kV)	345
CapX2020 Bemidji to Grand Rapids Project [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	70
Transmission Line Capacity (kV)	230
Capital Cost Spent to Date	10.9	10.9
Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	240
Transmission Line Capacity (kV)	500
Estimated Capital Expenditures	$ 300
Great Northern Transmission Line [Member] \| Minnesota Power [Member]
Transmission [Line Items]
Portion of Capital Expenditures GNTL	51.00%

Commitments, Guarantees and Contingencies - Environmental Matters (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 310
Minimum Payment Obligation in 2014	61.1
Minimum Payment Obligation in 2015	$ 25.7

Commitments, Guarantees and Contingencies - Other Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Years	Dec. 31, 2012
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Surety Bond	$ 29.7
Letters of Credit	2.6
Estimated Reclamation Liability	32.3
ALLETE Properties Performance and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Environmental Loss Contingency, Surety Bond and Letters of Credit	10.2
Performance and Maintenance Obligations	7.4
Town Center Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Community Development District Obligation, Bond	26.4
Community Development Distrcit Obligation, Bond Interest Rate	6.00%
Community Development District Obligation, Bond Term (in Years)	31
Community Development District Obligation, Ownership Percentage of Benefited Property	73.00%	73.00%
Community Development District Obligation, Annual Assessment	1.4
Palm Coast Park Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Community Development District Obligation, Bond	31.8
Community Development Distrcit Obligation, Bond Interest Rate	5.70%
Community Development District Obligation, Bond Term (in Years)	31
Community Development District Obligation, Ownership Percentage of Benefited Property	93.00%	93.00%
Community Development District Obligation, Annual Assessment	$ 2.1

Common Stock and Earnings Per Share - Summary of Common Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	12 Months Ended			3 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 31, 2014 Common Stock [Member]	Dec. 31, 2013 Common Stock [Member]	Dec. 31, 2012 Common Stock [Member]	Dec. 31, 2011 Common Stock [Member]	Dec. 31, 2010 Common Stock [Member]
Class of Stock [Line Items]
Common Stock Outstanding, Shares		41,400,000	39,400,000			41,401,000	39,377,000	37,513,000	35,817,000
Common Stock Outstanding, Value						$ 885.2	$ 784.7	$ 705.6	$ 636.1
Employee Stock Purchase Program, Shares						16,000	20,000	20,000
Employee Stock Purchase Program, Value						0.7	0.8	0.8
Invest Direct, Shares						395,000	474,000	437,000
Invest Direct, Value						18.5	19.2	17.2
Options and Stock Awards, Shares						301,000	95,000	109,000
Options and Stock Awards, Value						17.9	6.0	6.7
Equity Issuance Program, Shares						1,312,000	1,275,000	400,000
Equity Issuance Program, Value						63.4	53.1	16.0
Purchase of Non-Controlling Interest, Shares	200,000							222,000
Purchase of Non-Controlling Interest, Value								8.8
Contributions to Pension, Shares					400,000	0	0	508,000
Contributions to Pension, Value		$ 0	$ 0	$ 20.0	$ 19.5			$ 20.0
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share						0	200,000	300,000
Equity Issuance Program Shares Authorized						9,600,000
Equity Issuance Program Shares Available for Issuance						3,100,000

Common Stock and Earnings Per Share - Reconciliation of Basic and Diluted Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 33.0	$ 25.2	$ 14.0	$ 32.5	$ 28.9	$ 29.4	$ 14.4	$ 24.4	$ 104.7	$ 97.1	$ 93.8
Average Common Shares									39.7	37.6	35.3
Earnings Per Share	$ 0.82	$ 0.63	$ 0.36	$ 0.83	$ 0.76	$ 0.78	$ 0.39	$ 0.66	$ 2.64	$ 2.59	$ 2.66
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE									$ 104.7	$ 97.1	$ 93.8
Average Common Shares									39.8	37.6	35.4
Earnings Per Share	$ 0.82	$ 0.63	$ 0.35	$ 0.83	$ 0.75	$ 0.78	$ 0.39	$ 0.66	$ 2.63	$ 2.58	$ 2.65
Dilutive Securities (Shares)									0.1	0	0.1

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 04

-Paragraph 20

-Article 9

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 230

-SubTopic 10

-Section 45

-Paragraph 28

-URI http://asc.fasb.org/extlink&oid=31042434&loc=d3e3602-108585

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

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Other Comprehensive Income

-URI http://asc.fasb.org/extlink&oid=6519514

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Net Income

-URI http://asc.fasb.org/extlink&oid=6518256

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 944

-SubTopic 225

-Section S99

-Paragraph 1

-Subparagraph (SX 210.7-04.19)

-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 225

-SubTopic 10

-Section S99

-Paragraph 2

-Subparagraph (SX 210.5-03.18)

-URI http://asc.fasb.org/extlink&oid=26872669&loc=d3e20235-122688

Reference 8: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 944

-SubTopic 225

-Section S99

-Paragraph 1

-Subparagraph (SX 210.7-04.22)

-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 9: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 220

-SubTopic 10

-Section 45

-Paragraph 6

-URI http://asc.fasb.org/extlink&oid=28358780&loc=d3e565-108580

Reference 10: http://www.xbrl.org/2003/role/presentationRef

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 03

-Paragraph 19

-Article 5

+ Details

Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 4.6	$ 5.1	$ 2.5
Gain on Sale of Available-for-sale Securities	2.2	0	0
Investment and Other Income	2.5	0.9	1.9
Total Other Income	$ 9.3	$ 6.0	$ 4.4

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Current Income Tax Expense (Benefit), Continuing Operations [Abstract]

Current Federal Tax Expense (Benefit)

$ 0

^[1]

$ 0

^[1]

$ 1.4

^[1]

Current State Tax Expense (Benefit)

0.1

^[1]

0.5

^[1]

(1.6)

^[1]

Total Current Tax Expense (Benefit)

0.1

0.5

(0.2)

Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]

Deferred Federal Tax Expense

22.9

^[2]

37.0

^[2]

27.4

^[2]

Deferred State Tax Expense (Benefit)

6.5

^[2]

1.4

^[2]

9.3

^[2]

Investment Tax Credit Amortization

(0.8)

(0.9)

Total Deferred Tax Expense

28.6

37.5

35.8

Total Income Tax Expense

$ 28.7

$ 38.0

$ 35.6

[1]

[2]

Income Tax Expense - Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Expense [Abstract]
Income Before Non-Controlling Interest and Income Taxes		$ 133.4	$ 135.1	$ 129.2
Statutory Federal Income Tax Rate		35.00%	35.00%	35.00%
Income Taxes Computed at 35 Percent Statutory Federal Rate		46.7	47.3	45.2
Increase (Decrease) in Tax [Abstract]
State Income Taxes - Net of Federal Income Tax Benefit		4.3	1.2	6.0
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Expense (Benefit)		28.6	37.5	35.8
Regulatory Differences for Utility Plant		(2.2)	(2.2)	(1.2)
Production Tax Credits		(19.2)	(7.6)	(4.3)
Other		(0.9)	(0.7)	(1.0)
Income Tax Expense		28.7	38.0	35.6
Effective Income Tax Rate		21.50%	28.10%	27.60%
PPACA Elimination of Medicare Part D [Member]
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Expense (Benefit)	2.9	0	0	(2.9)
2010 Rate Case Stipulation Agreement [Member]
Unusual or Infrequent Item [Line Items]
Deferred Income Tax Expense (Benefit)		$ 0	$ 0	$ (6.2)

Income Tax Expense - Deferred Tax Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Deferred Tax Assets [Abstract]

Employee Benefits and Compensation

$ 66.3

$ 120.2

Property Related

82.2

59.8

NOL Carryforwards

112.8

90.8

Tax Credit Carryforwards

55.1

28.3

Other

16.9

24.6

Gross Deferred Tax Assets

333.3

323.7

Deferred Tax Asset Valuation Allowance

(8.0)

(2.4)

Total Deferred Tax Assets

325.3

321.3

Deferred Tax Liabilities [Abstract]

Property Related

656.2

577.1

Regulatory Asset for Benefit Obligations

58.7

104.3

Unamortized Investment Tax Credits

11.1

11.9

Partnership Basis Differences

36.7

28.6

Other

22.7

30.1

Total Deferred Tax Liabilities

785.4

752.0

Net Deferred Income Taxes

460.1

430.7

Net Current Deferred Tax Assets

19.0

^[1]

Net Current Deferred Tax Liabilities

^[2]

6.9

^[2]

Net Long-Term Deferred Tax Liabilities

$ 479.1

$ 423.8

[1]	In 2013, Current Deferred Tax Assets reflect the expectation of using federal NOL carryforward deductions in 2014.
[2]	Included in Other Current Assets and Other Current Liabilities.

Income Tax Expense - NOL and Tax Credit Carryforwards (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforward

$ 279,800,000

^[1]

$ 244,100,000

^[1]

Tax Credit Carryforwards

35,500,000

16,000,000

NOL and Federal Tax Credit Carryforwards, Valuation Allowance

State [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforward

156,300,000

^[1]

90,600,000

^[1]

Tax Credit Carryforwards

11,900,000

^[2]

10,300,000

^[2]

State Tax Credit Carryforwards, Valuation Allowance

$ 7,700,000

[1]	Pretax amounts
[2]	Net of $7.7 million valuation allowance.

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 2.7	$ 11.4	$ 12.3
Additions for Tax Positions Related to the Current Year	0.1	0	0
Additions for Tax Positions Related to Prior Years	1.3	0	0
Reduction for Tax Positions Related to Prior Years	0	(8.7)	(0.9)
Reductions for Settlements	(2.9)	0	0
Balance as of December 31	1.2	2.7	11.4
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.2
Unrecognized Tax Benefits, Accrued Interest	0.5	0.5	1.1
Unrecognized Tax Benefits, Penalties	0	0	0
Unrecognized Tax Benefits, Interest Expense (Reduction)	0	(0.6)	0.4
Reasonably Possible Change in Unrecognized Tax Benefits in Next 12 Months	$ 0.2

Reclassifications Out of Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	$ (17.1)	$ (22.0)
Other Comprehensive Income Before Reclassifications	4.6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(0.3)
Net Other Comprehensive Income	4.9	6.9	(5.7)
Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]
AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items	(2.7)
AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement items, Prior Service Costs, Before Tax	0.8
AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items, Actuarial Gains and Losses, Before Tax	(3.5)
Other Income (Expense) - Other [Member]
Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]
AOCI Reclassification, Unrealized Gains on Available-for-sale Securities, Before Tax	2.2
Income Tax Expense [Member]
Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]
AOCI Reclassification, Unrealized Gains on Available-for-sale Securities, Tax	(0.9)
AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement Items, Tax	1.1
Unrealized Gains and Losses on Available-for-sale Securities [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	(0.1)	(0.1)
Other Comprehensive Income Before Reclassifications	1.3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	1.3
Net Other Comprehensive Income	0
Defined Benefit Pension, Other Postretirement Items [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	(16.7)	(21.5)
Other Comprehensive Income Before Reclassifications	3.2
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1.6)
Net Other Comprehensive Income	4.8
Gains and Losses on Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	(0.3)	(0.4)
Other Comprehensive Income Before Reclassifications	0.1
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	0
Net Other Comprehensive Income	$ 0.1

Pension and Other Postretirement Benefit Plans - Contributions (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 31, 2014 Pension [Member]	Dec. 31, 2014 Pension [Member]	Dec. 31, 2013 Pension [Member]	Dec. 31, 2012 Pension [Member]	Dec. 31, 2014 Postretirement Health and Life [Member]	Dec. 31, 2013 VEBA [Member]	Dec. 31, 2012 VEBA [Member]	Dec. 31, 2013 Grantor Trust [Member]	Dec. 31, 2012 Grantor Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Contributions						$ 0	$ 7.3		$ 10.8	$ 1.5	$ 2.0	$ 0
ALLETE Common Stock Contributed to Pension Plan	0	0	20.0	19.5
ALLETE Common Stock Contributed to Pension Plan, Shares				400
Defined Benefit Plans, Estimated Employer Contributions					We do not expect to make any additional contributions to the defined benefit pension plan in 2014, beyond the $19.5 million contribution to the defined benefit pension plan made in January 2014.
Defined Benefit Plans, Estimated Employer Contributions								0
Defined Contribution Plan, Employer Contributions	$ 8.4	$ 7.7

Pension and Other Postretirement Benefit Plans - Obligation and Funded Status (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Change in Plan Assets [Roll Forward]

Non-Current Liabilities

$ (133.4)

$ (228.2)

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Accumulated Benefit Obligation

577.6

598.7

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

652.1

597.5

Service Cost

9.9

9.1

7.6

Interest Cost

26.0

26.4

27.4

Actuarial (Gain) Loss

(49.2)

38.5

Benefits Paid

(33.5)

(30.9)

Participant Contributions

17.5

11.5

Obligation, End of Year

622.8

652.1

597.5

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

460.1

432.4

Actual Return on Plan Assets

56.5

38.7

Employer Contribution

18.5

^[1]

19.9

^[1]

Fair Value, End of Year

501.6

460.1

432.4

Funded Status, End of Year

(121.2)

(192.0)

Current Liabilities

(1.1)

Non-Current Liabilities

(120.1)

(190.9)

Postretirement Health and Life [Member]

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

168.8

210.6

Service Cost

3.9

4.2

3.8

Interest Cost

6.8

9.4

10.8

Actuarial (Gain) Loss

(18.8)

(43.2)

Benefits Paid

(9.9)

(9.5)

Participant Contributions

2.7

2.6

Plan Amendments

(5.3)

Settlements

(1.6)

^[2]

Obligation, End of Year

151.9

168.8

210.6

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

131.0

121.0

Actual Return on Plan Assets

21.4

14.3

Employer Contribution

11.7

2.3

Participant Contributions, Excluding Key Employees

2.7

2.5

Benefits Paid, Excluding Key Employees

(9.8)

(9.1)

Fair Value, End of Year

157.0

131.0

121.0

Funded Status, End of Year

5.1

(37.8)

Non-Current Assets

19.4

Current Liabilities

(0.9)

(0.8)

Non-Current Liabilities

(13.4)

(37.0)

Grantor Trust [Member]

Change in Plan Assets [Roll Forward]

Other Investments, Grantor Trust

$ 17.8

$ 22.1

[1]	Includes participant contributions noted above.
[2]	Result of the exit from a legacy benefit plan.

Pension and Other Postretirement Benefit Plans - Unrecognized Costs (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ 194.9	$ 286.8
Prior Service Cost (Credit)	0.4	0.7
Total Unrecognized Costs (Credit)	195.3	287.5
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	(9.0)	23.5
Prior Service Cost (Credit)	(10.1)	(13.1)
Total Unrecognized Costs (Credit)	$ (19.1)	$ 10.4

Pension and Other Postretirement Benefit Plans - Components of Net Periodic Expense (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Service Cost

$ 9.9

$ 9.1

$ 7.6

Interest Cost

26.0

26.4

27.4

Expected Return on Plan Assets

(35.2)

(35.4)

(34.6)

Amortization of Loss

21.5

17.5

12.1

Amortization of Prior Service Cost (Credit)

0.3

Net Expense (Credit)

22.5

17.9

12.8

Postretirement Health and Life [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Service Cost

3.9

4.2

3.8

Interest Cost

6.8

9.4

10.8

Expected Return on Plan Assets

(9.7)

(9.9)

(9.7)

Amortization of Loss

1.6

7.5

8.5

Amortization of Prior Service Cost (Credit)

(2.5)

(1.7)

Amortization of Transition Obligation

0.1

Effect of Plan Settlement

(1.6)

^[1]

Net Expense (Credit)

$ (1.5)

$ 9.6

$ 11.8

[1]	Result of the exit from a legacy benefit plan.

Pension and Other Postretirement Benefit Plans - Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Amortization of Prior Service (Cost) Credit

$ (0.8)

Amortization of Loss

(3.5)

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Net (Gain) Loss

(70.4)

35.2

Amortization of Prior Service (Cost) Credit

(0.3)

Amortization of Loss

(21.5)

(17.5)

Total Recognized in Other Comprehensive Income and Regulatory Assets

(92.2)

17.4

Postretirement Health and Life [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Net (Gain) Loss

(30.2)

(47.5)

Prior Service Credit Arising During the Period

(5.3)

Amortization of Prior Service (Cost) Credit

2.5

1.7

Amortization of Transition Obligation

(0.1)

Amortization of Loss

(1.6)

(7.5)

Amount Recognized due to Plan Settlement

(0.2)

^[1]

Total Recognized in Other Comprehensive Income and Regulatory Assets

$ (29.5)

$ (58.7)

[1]	Result of the exit from a legacy benefit plan.

- Definition

Amount before tax of gain (loss) adjustment to other comprehensive income (loss) resulting from settlement or curtailment of defined benefit pension and other postretirement defined benefit plans.

+ References+ Details

Pension and Other Postretirement Benefit Plans - Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) (Pension [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 622.8	$ 652.1
Accumulated Benefit Obligation	577.6	598.7
Fair Value of Plan Assets	$ 501.6	$ 460.1

Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2014	$ 33.9
2015	34.9
2016	35.8
2017	36.9
2018	37.8
Years 2019 - 2023	200.2
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2014	7.7
2015	8.4
2016	8.8
2017	9.2
2018	9.4
Years 2019 - 2023	$ 50.6

Pension and Other Postretirement Benefit Plans - Costs Recorded in Regulatory Long-Term Assets or Liabilities and AOCI Expected to be Recognized as a Component of Net Pension and Postretirement Benefit Costs in the Next Fiscal Year (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 14.2
Prior Service Cost (Credit)	0.3
Total Pension and Postretirement Health and Life Cost (Credit)	14.5
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	0.5
Prior Service Cost (Credit)	(2.5)
Total Pension and Postretirement Health and Life Cost (Credit)	$ (2.0)

Pension and Other Postretirement Benefit Plans - Weighted-Average Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Pension [Member]

Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]

Discount Rate

4.93%

4.10%

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Discount Rate

4.10%

4.54%

5.36%

Expected Long-Term Return on Plan Assets

8.25%

^[1]

8.25%

8.50%

Pension [Member] | Minimum [Member]

Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]

Rate of Compensation Increase

3.70%

4.30%

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Rate of Compensation Increase

4.30%

Pension [Member] | Maximum [Member]

Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]

Rate of Compensation Increase

4.30%

4.60%

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Rate of Compensation Increase

4.60%

Postretirement Health and Life [Member]

Weighted-Average Assumptions Used to Determine Benefit Obligation [Abstract]

Discount Rate

4.96%

4.13%

Trend Rate

7.25%

9.25%

Ultimate Trend Rate

5.00%

Year Ultimate Trend Rate Effective

2020

2019

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Discount Rate

4.13%

4.56%

5.40%

Postretirement Health and Life [Member] | Minimum [Member]

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Expected Long-Term Return on Plan Assets

6.60%

6.80%

Postretirement Health and Life [Member] | Maximum [Member]

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]

Expected Long-Term Return on Plan Assets

8.25%

8.50%

[1]	The expected long-term rate of return used to determine net periodic benefit expense for 2014 has been reduced to 8.00 percent.

Pension and Other Postretirement Benefit Plans - Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates (Details) (Postretirement Health and Life [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Effect of One Percent Increase on Total of Postretirement Health and Life Service and Interest Cost	$ 1.6
Effect of One Percent Increase on Postretirement Health and Life Obligation	16.0
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.3)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (13.4)

Pension and Other Postretirement Benefit Plans - Plan Asset Allocations (Details)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Pension [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

100.00%

Defined Benefit Plans, Company Stock Included in Equity Securities (in Shares)

Plan Asset Target Allocation

100.00%

Pension [Member] | Equity Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

52.00%

54.00%

Plan Asset Target Allocation

52.00%

Pension [Member] | Debt Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

34.00%

28.00%

Plan Asset Target Allocation

30.00%

Pension [Member] | Private Equity [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

9.00%

13.00%

Plan Asset Target Allocation

9.00%

Pension [Member] | Real Estate [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

5.00%

Plan Asset Target Allocation

9.00%

Postretirement Health and Life [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

100.00%

^[1]

100.00%

^[1]

Plan Asset Target Allocation

100.00%

^[1]

Postretirement Health and Life [Member] | Equity Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

63.00%

^[1]

56.00%

^[1]

Plan Asset Target Allocation

50.00%

^[1]

Postretirement Health and Life [Member] | Debt Securities [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

29.00%

^[1]

35.00%

^[1]

Plan Asset Target Allocation

30.00%

^[1]

Postretirement Health and Life [Member] | Private Equity [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

8.00%

^[1]

9.00%

^[1]

Plan Asset Target Allocation

10.00%

^[1]

Postretirement Health and Life [Member] | Real Estate [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Actual Plan Asset Allocation

0.00%

^[1]

0.00%

^[1]

Plan Asset Target Allocation

10.00%

^[1]

[1]	Includes VEBAs and irrevocable grantor trusts.

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures (Details) (USD $)
In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Pension [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

$ 501.6

$ 460.1

$ 432.4

Pension [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

234.2

213.0

Pension [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

194.1

163.3

Pension [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

73.3

83.8

Pension [Member] | U.S. Large-cap [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

80.2

^[1]

79.0

^[1]

Pension [Member] | U.S. Large-cap [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

20.9

^[1]

43.0

^[1]

Pension [Member] | U.S. Large-cap [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

59.3

^[1]

36.0

^[1]

Pension [Member] | U.S. Large-cap [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[1]

Pension [Member] | U.S. Mid-cap Growth [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

36.1

^[1]

33.6

^[1]

Pension [Member] | U.S. Mid-cap Growth [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

9.4

^[1]

18.3

^[1]

Pension [Member] | U.S. Mid-cap Growth [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

26.7

^[1]

15.3

^[1]

Pension [Member] | U.S. Mid-cap Growth [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[1]

Pension [Member] | U.S. Small-cap [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

38.1

^[1]

33.6

^[1]

Pension [Member] | U.S. Small-cap [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

9.9

^[1]

18.3

^[1]

Pension [Member] | U.S. Small-cap [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

28.2

^[1]

15.3

^[1]

Pension [Member] | U.S. Small-cap [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[1]

Pension [Member] | International [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

104.7

96.4

Pension [Member] | International [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

61.2

50.5

Pension [Member] | International [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

43.5

45.9

Pension [Member] | International [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Mutual Funds [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

130.1

72.5

Pension [Member] | Mutual Funds [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

130.1

72.5

Pension [Member] | Mutual Funds [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Mutual Funds [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Fixed Income [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

36.4

61.2

Pension [Member] | Fixed Income [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

10.4

Pension [Member] | Fixed Income [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

36.4

50.8

Pension [Member] | Fixed Income [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Cash Equivalents [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

2.7

Pension [Member] | Cash Equivalents [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

2.7

Pension [Member] | Cash Equivalents [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Cash Equivalents [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Private Equity Funds [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

46.8

58.9

Pension [Member] | Private Equity Funds [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Private Equity Funds [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Private Equity Funds [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

46.8

58.9

Pension [Member] | Real Estate [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

26.5

24.9

Pension [Member] | Real Estate [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Real Estate [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Real Estate [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

26.5

24.9

Postretirement Health and Life [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

157.0

131.0

121.0

Postretirement Health and Life [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

128.4

99.2

Postretirement Health and Life [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

15.5

18.3

Postretirement Health and Life [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

13.1

13.5

Postretirement Health and Life [Member] | U.S. Large-cap [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

28.3

^[2]

16.7

^[2]

Postretirement Health and Life [Member] | U.S. Large-cap [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

28.3

^[2]

16.7

^[2]

Postretirement Health and Life [Member] | U.S. Large-cap [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[2]

Postretirement Health and Life [Member] | U.S. Large-cap [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[2]

Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

17.6

^[2]

13.2

^[2]

Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

17.6

^[2]

13.2

^[2]

Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[2]

Postretirement Health and Life [Member] | U.S. Mid-cap Growth [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[2]

Postretirement Health and Life [Member] | U.S. Small-cap [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

18.2

^[2]

13.3

^[2]

Postretirement Health and Life [Member] | U.S. Small-cap [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

18.2

^[2]

13.3

^[2]

Postretirement Health and Life [Member] | U.S. Small-cap [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[2]

Postretirement Health and Life [Member] | U.S. Small-cap [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

^[2]

Postretirement Health and Life [Member] | International [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

33.4

30.3

Postretirement Health and Life [Member] | International [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

33.4

30.3

Postretirement Health and Life [Member] | International [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | International [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Mutual Funds [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

30.8

25.5

Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

30.8

25.5

Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Mutual Funds [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Fixed Income [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

15.5

18.5

Postretirement Health and Life [Member] | Fixed Income [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.2

Postretirement Health and Life [Member] | Fixed Income [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

15.5

18.3

Postretirement Health and Life [Member] | Fixed Income [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Cash Equivalents [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.1

Postretirement Health and Life [Member] | Cash Equivalents [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.1

Postretirement Health and Life [Member] | Cash Equivalents [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Cash Equivalents [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Private Equity Funds [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

13.1

13.5

Postretirement Health and Life [Member] | Private Equity Funds [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Private Equity Funds [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Private Equity Funds [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

$ 13.1

$ 13.5

[1]

[2]

The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).

Pension and Other Postretirement Benefit Plans - Recurring Fair Value Measures, Activity in Level 3 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 58.9	$ 69.0
Actual Return on Plan Assets	2.3	(9.7)
Purchases, sales, and settlements, net	(14.4)	(0.4)
Ending Balance	46.8	58.9
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	24.9	21.7
Actual Return on Plan Assets	2.1	3.4
Purchases, sales, and settlements, net	(0.5)	(0.2)
Ending Balance	26.5	24.9
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	13.5	14.0
Actual Return on Plan Assets	2.4	0.2
Purchases, sales, and settlements, net	(2.8)	(0.7)
Ending Balance	$ 13.1	$ 13.5

Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Stock and Incentive Plans [Abstract]
ESOP Employer Loan, Description	In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use 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.
ESOP Compensation Expense	$ 8.4	$ 7.7	$ 7.4
ESOP Shares, Allocated	2.0	2.2	2.2
ESOP Shares, Unallocated	0.5	0.7	1.0
ESOP Shares, Total	2.5	2.9	3.2
Fair Value of Unallocated ESOP Shares	$ 24.1	$ 28.7	$ 42.0

Employee Stock and Incentive Plans - Stock-Based Compensation (Details)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Grants

^[1]

Exercised

287,379

49,075

80,798

Options Outstanding

108,299

395,678

460,234

560,887

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Vesting Period

3 years

Restricted Stock Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Vesting Period

3 years

Employee Stock Purchase Plan (ESPP) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

ESPP Discount

5.00%

Executive Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Common Stock Reserved

900,000

Shares Available for Issuance

600,000

[1]	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

- Definition

Number of share options (or share units) exercised during the current period.

+ References+ Details

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	$ 2.4	$ 2.1	$ 1.6
Income Tax Benefit	1.0	0.9	0.7
Capitalized Stock-Based Compensation Expense	0	0	0
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	1.7	1.4	1.1
Unrecognized Compensation Cost	1.7
Weighted Average Period for Recognition	1 year 8 months 12 days
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Expense	0.7	0.7	0.5
Unrecognized Compensation Cost	$ 0.7
Weighted Average Period for Recognition	1 year 8 months 12 days

Employee Stock and Incentive Plans - Non-Qualified Stock Options (Details) (USD $)
In Millions, except Share data, unless otherwise specified

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2008

Number of Options [Abstract]

Outstanding as of January 1,

395,678

460,234

560,887

Granted

^[1]

Exercised

287,379

49,075

80,798

Forfeited

15,481

19,855

Outstanding as of December 31,

108,299

395,678

460,234

Exercisable as of December 31,

108,299

395,678

460,234

Weighted Average Exercise Price [Abstract]

Outstanding as of January 1,

$ 42.28

$ 41.68

$ 40.69

Granted

$ 0.00

^[1]

$ 0.00

^[1]

$ 0.00

^[1]

Exercised

$ 41.60

$ 35.84

$ 34.25

Forfeited

$ 0.00

$ 44.86

$ 43.96

Outstanding as of December 31,

$ 44.10

$ 42.28

$ 41.68

Exercisable as of December 31,

$ 43.17

$ 41.71

$ 41.59

Proceeds from Stock Options Exercised

$ 11.4

Weighted Average Grant Date Intrinsic Value of Options Granted

$ 6.18

Total Intrinsic Value of Options Exercised

$ 2.2

$ 0.3

$ 0.5

[1]	Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Employee Stock and Incentive Plans - Stock Options, Range of Exercise Price (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
$37.76 to $41.35 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise Price Range, Lower Range Limit	$ 37.76
Exercise Price Range, Upper Range Limit	$ 41.35
Number Outstanding	44,263
Weighted Average Remaining Contractual Term (in Years)	2 years 7 months 23 days
Weighted Average Exercise Price	$ 40.18
Number Exercisable	44,263
Weighted Average Remaining Contractual Term (in Years)	2 years 7 months 23 days
Weighted Average Exercise Price	$ 40.18
$44.15 to $48.65 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise Price Range, Lower Range Limit	$ 44.15
Exercise Price Range, Upper Range Limit	$ 48.65
Number Outstanding	64,036
Weighted Average Remaining Contractual Term (in Years)	2 years 8 months 5 days
Weighted Average Exercise Price	$ 46.81
Number Exercisable	64,036
Weighted Average Remaining Contractual Term (in Years)	2 years 8 months 5 days
Weighted Average Exercise Price	$ 46.81

Employee Stock and Incentive Plans - Performance Shares and Restricted Stock Units (Details) (USD $)
In Millions, except Share data, unless otherwise specified

3 Months Ended

12 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Performance Shares [Member]

Number of Shares [Abstract]

As of January 1,

114,765

107,899

128,333

122,489

Granted

43,081

41,332

45,830

^[1]

38,764

^[1]

39,312

^[1]

Awarded

(36,515)

(18,605)

(41,009)

(32,368)

Unearned Grant Award

(18,606)

(17,575)

Forfeited

(1,753)

(614)

(1,100)

As of December 31,

114,765

107,899

128,333

Weighted Average Grant Date Fair Value [Abstract]

As of January 1,

$ 47.02

$ 40.73

$ 36.54

$ 38.15

Granted

$ 52.15

^[1]

$ 44.70

^[1]

$ 41.00

^[1]

Awarded

$ 35.10

$ 34.25

$ 48.10

Unearned Grant Award

$ 35.10

$ 34.25

$ 0.00

Forfeited

$ 47.26

$ 34.49

$ 34.35

As of December 31,

$ 47.02

$ 40.73

$ 36.54

Performance Period

3 years

Grants, Grant Date Fair Value

$ 2.0

$ 2.2

Awards, Grant Date Fair Value

1.5

0.7

Restricted Stock Units [Member]

Number of Shares [Abstract]

As of January 1,

55,982

56,415

63,464

43,803

Granted

17,491

19,193

21,440

^[1]

18,162

^[1]

20,136

^[1]

Awarded

(18,860)

(20,939)

(24,707)

(215)

Forfeited

(934)

(504)

(260)

As of December 31,

55,982

56,415

63,464

Weighted Average Grant Date Fair Value [Abstract]

As of January 1,

$ 40.85

$ 36.61

$ 32.57

$ 30.61

Granted

$ 43.41

^[1]

$ 40.83

^[1]

$ 36.74

^[1]

Awarded

$ 32.03

$ 29.43

$ 30.30

Forfeited

$ 41.02

$ 31.80

$ 29.41

As of December 31,

$ 40.85

$ 36.61

$ 32.57

Performance Period

3 years

Grants, Grant Date Fair Value

0.9

0.8

Awards, Grant Date Fair Value

$ 0.7

[1]	Shares granted includes accrued dividends.

Quarterly Financial Data (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Data (Unaudited) [Abstract]
Operating Revenue	$ 268.0	$ 251.0	$ 235.6	$ 263.8	$ 256.0	$ 248.8	$ 216.4	$ 240.0	$ 1,018.4	$ 961.2	$ 928.2
Operating Income	46.9	38.4	24.4	44.4	47.9	45.6	23.3	38.4	154.1	155.2	150.0
Net Income Attributable to ALLETE	$ 33.0	$ 25.2	$ 14.0	$ 32.5	$ 28.9	$ 29.4	$ 14.4	$ 24.4	$ 104.7	$ 97.1	$ 93.8
Basic Earnings Per Share of Common Stock	$ 0.82	$ 0.63	$ 0.36	$ 0.83	$ 0.76	$ 0.78	$ 0.39	$ 0.66	$ 2.64	$ 2.59	$ 2.66
Diluted Earnings Per Share of Common Stock	$ 0.82	$ 0.63	$ 0.35	$ 0.83	$ 0.75	$ 0.78	$ 0.39	$ 0.66	$ 2.63	$ 2.58	$ 2.65