Document and Entity Information Document (USD $)	12 Months Ended
Document and Entity Information Document (USD $)	Dec. 31, 2014	Feb. 02, 2015	Jun. 30, 2014
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	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and Cash Equivalents	$ 145.8	$ 97.3
Accounts Receivable (Less Allowance of $1.1 and $1.1)	103.0	96.3
Inventories	80.5	59.3
Prepayments and Other	82.0	35.1
Deferred Income Taxes	7.5	19.0
Total Current Assets	418.8	307.0
Property, Plant and Equipment - Net	3,286.4	2,576.5
Regulatory Assets	357.3	263.8
Investment in ATC	121.1	114.6
Other Investments	114.4	146.3
Other Non-Current Assets	62.8	68.6
Total Assets	4,360.8	3,476.8
Current Liabilities
Accounts Payable	134.1	99.9
Accrued Taxes	38.7	34.8
Accrued Interest	18.0	15.7
Long-Term Debt Due Within One Year	100.7	27.2
Notes Payable	3.7	0
Other	120.8	52.6
Total Current Liabilities	416.0	230.2
Long-Term Debt	1,272.8	1,083.0
Deferred Income Taxes	510.7	479.1
Regulatory Liabilities	94.2	81.0
Defined Benefit Pension and Other Postretirement Benefit Plans	190.9	133.4
Other Non-Current Liabilities	265.0	127.2
Total Liabilities	2,749.6	2,133.9
Commitments and Contingencies (Note 12)
Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 45.9 and 41.4 Shares Outstanding	1,107.6	885.2
Unearned ESOP Shares	(7.2)	(14.3)
Accumulated Other Comprehensive Loss	(21.1)	(17.1)
Retained Earnings	530.1	489.1
Total ALLETE Equity	1,609.4	1,342.9
Non-Controlling Interest in Subsidiaries	1.8	0
Total Equity	1,611.2	1,342.9
Total Liabilities and Equity	$ 4,360.8	$ 3,476.8

Consolidated Balance Sheet Parentheticals (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.1	$ 1.1
Common Stock [Abstract]
Common Stock, Par Value	$ 0	$ 0
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	45.9	41.4

Consilidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Statement of Income [Abstract]
Operating Revenue	$ 1,136.8	$ 1,018.4	$ 961.2
Operating Expenses
Fuel and Purchased Power	356.1	334.8	308.7
Operating and Maintenance	456.2	412.9	397.1
Depreciation	135.7	116.6	100.2
Total Operating Expenses	948.0	864.3	806.0
Operating Income	188.8	154.1	155.2
Other Income (Expense)
Interest Expense	(54.8)	(50.3)	(45.5)
Equity Earnings in ATC	19.6	20.3	19.4
Other	8.6	9.3	6.0
Total Other Expense	(26.6)	(20.7)	(20.1)
Income Before Non-Controlling Interest and Income Taxes	162.2	133.4	135.1
Income Tax Expense	36.7	28.7	38.0
Net Income	125.5	104.7	97.1
Less: Non-Controlling Interest in Subsidiaries	0.7	0	0
Net Income Attributable to ALLETE	$ 124.8	$ 104.7	$ 97.1
Average Shares of Common Stock and Per Share Data
Basic (in shares)	42.9	39.7	37.6
Diluted (in shares)	43.1	39.8	37.6
Basic Earnings Per Share of Common Stock	$ 2.91	$ 2.64	$ 2.59
Diluted Earnings Per Share of Common Stock	$ 2.90	$ 2.63	$ 2.58
Dividends Per Share of Common Stock	$ 1.96	$ 1.90	$ 1.84

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net Income	$ 125.5	$ 104.7	$ 97.1
Other Comprehensive Income (Loss) [Abstract]
Unrealized Gain (Loss) on Securities - Net of Income Taxes of $(0.2), $– and $0.8	(0.2)	0	1.2
Unrealized Gain (Loss) on Derivatives - Net of Income Taxes of $0.1, $– and $(0.1)	0.2	0.1	(0.2)
Defined Benefit Pension and Other Postretirement Benefit Plans - Net of Income Taxes of $(2.8), $3.3 and $3.9	(4.0)	4.8	5.9
Total Other Comprehensive Income (Loss)	(4.0)	4.9	6.9
Total Comprehensive Income	121.5	109.6	104.0
Less: Non-Controlling Interest in Subsidiaries	0.7	0	0
Comprehensive Income Attributable to ALLETE	$ 120.8	$ 109.6	$ 104.0

Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain (Loss) on Securities, Taxes	$ (0.2)	$ 0	$ 0.8
Unrealized Loss on Derivatives, Taxes	0.1	0	(0.1)
Defined Benefit Pension and Other Postretirement Benefit Plans, Taxes	$ (2.8)	$ 3.3	$ 3.9

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Activities
Net Income	$ 125.5	$ 104.7	$ 97.1
Allowance for Funds Used During Construction - Equity	(7.8)	(4.6)	(5.1)
Income from Equity Investments, Net of Dividends	(2.6)	(4.2)	(3.7)
Loss (Gain) on Sale of Assets / Investments	(0.2)	(2.6)	0.2
Depreciation Expense	135.7	116.6	100.2
Other Amortization	0.7	1.0	1.0
Amortization of Power Purchase Agreements	(12.7)	0	0
Deferred Income Tax Expense	32.7	28.6	37.5
Share-Based Compensation Expense	2.3	2.4	2.1
ESOP Compensation Expense	9.1	8.4	7.7
Defined Benefit Pension and Other Postretirement Benefit Expense	12.8	21.0	27.5
Bad Debt Expense	1.8	1.3	1.0
Changes in Operating Assets and Liabilities
Accounts Receivable	(3.5)	(8.6)	(10.1)
Inventories	(17.5)	10.5	(0.7)
Prepayments and Other	4.8	(1.4)	(6.5)
Accounts Payable	10.9	1.1	(1.5)
Other Current Liabilities	(3.5)	1.4	21.8
Cash Contributions to Defined Benefit Pension and Other Postretirement Plans	0	(10.8)	(8.8)
Changes in Regulatory and Other Non-Current Assets	(21.3)	(18.3)	(20.9)
Changes in Regulatory and Other Non-Current Liabilities	2.6	(7.1)	0.8
Cash from Operating Activities	269.8	239.4	239.6
Investing Activities
Proceeds from Sale of Available-for-sale Securities	3.6	16.1	1.5
Payments for Purchase of Available-for-sale Securities	(5.0)	(4.7)	(1.8)
Acquisitions of Subsidiaries – Net of Cash Acquired	(60.3)	0	0
Investment in ATC	(3.9)	(3.1)	(4.7)
Changes to Other Investments	33.0	(12.3)	(9.6)
Additions to Property, Plant and Equipment	(572.8)	(328.5)	(405.8)
Construction Costs for Development Project	(25.7)	0	0
Changes in Escrow for Acquisition	5.4	(5.4)	0
Proceeds from Sale of Assets	0	1.3	0.3
Cash for Investing Activities	(625.7)	(336.6)	(420.1)
Financing Activities
Proceeds from Issuance of Common Stock	200.6	98.2	77.0
Proceeds from Issuance of Long-Term Debt	375.0	169.8	180.6
Changes in Restricted Cash	(1.8)	0	0
Changes in Notes Payable	3.7	0	(1.1)
Reductions of Long-Term Debt	(134.5)	(77.7)	(25.9)
Acquisition of Non-Controlling Interest	(6.0)	0	0
Construction Deposits Received for Development Project	54.3	0	0
Debt Issuance Costs	(3.1)	(1.4)	(1.3)
Dividends on Common Stock	(83.8)	(75.2)	(69.1)
Cash from Financing Activities	404.4	113.7	160.2
Change in Cash and Cash Equivalents	48.5	16.5	(20.3)
Cash and Cash Equivalents at Beginning of Period	97.3	80.8	101.1
Cash and Cash Equivalents at End of Period	$ 145.8	$ 97.3	$ 80.8

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, 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 Securities - Net	0
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
Comprehensive Income
Net Income	125.5	125.5
Other Comprehensive Income - Net of Tax
Unrealized Gain (Loss) on Securities - Net	(0.2)		(0.2)
Unrealized Gain (Loss) on Derivatives - Net	0.2		0.2
Defined Benefit Pension and Other Postretirement Plans - Net	(4.0)		(4.0)
Total Comprehensive Income	121.5
Non-Controlling Interest in Subsidiaries	(0.7)	(0.7)
Comprehensive Income Attributable to ALLETE	120.8
Common Stock Issued - Net	222.4				222.4
Dividends Declared	(83.8)	(83.8)
ESOP Shares Earned	7.1			7.1
Balance at Dec. 31, 2014	$ 1,609.4	$ 530.1	$ (21.1)	$ (7.2)	$ 1,107.6

Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

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.

On February 10, 2015, ALLETE acquired U.S. Water Services for $168 million and a contingent amount to be paid in 2019 based on U.S. Water Services’ future earnings. U.S. Water Services, an integrated industrial water management company headquartered in St. Michael, Minnesota, has a national footprint serving a growing and diverse mix of over 3,600 industrial customers, with recurring revenues and customer retention that exceeds 90 percent. U.S. Water Services provides integrated water management for industry, combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services helps customers achieve efficient and sustainable use of their energy systems, is a leading provider to the biofuels industry, and has a growing presence in the power generation and midstream oil and gas industries. The acquisition of U.S. Water Services is consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. We expect to finalize the allocation of the purchase price during the first half of 2015. Transaction costs related to the acquisition were expensed as incurred and were not material to the 2014 Consolidated Statement of Income.

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 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is 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 our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and 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 jurisdictions.

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 2014, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

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

Land 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.)

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	2014		2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$51.3		$47.5		$42.7
Cash Paid During the Period for Income Taxes		$5.1		$0.5	—
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$21.7		$8.3	$20.2
Capitalized Asset Retirement Costs		$22.4	$(0.7)			$17.1
AFUDC – Equity		$7.8		$4.6		$5.1
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan		$19.5	—		—

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	2014		2013
Millions
Trade Accounts Receivable
Billed		$85.5		$78.7
Unbilled	18.6		18.7
Less: Allowance for Doubtful Accounts	1.1		1.1
Total Accounts Receivable		$103.0		$96.3

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 10 Large Power Customers. Receivables from these customers totaled $14.7 million at December 31, 2014 ($14.2 million at December 31, 2013). 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 10.8 percent of consolidated revenue in 2014 (12.0 percent in 2013; 12.3 percent in 2012).

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	2014		2013
Millions
Fuel (a)		$29.0		$13.1
Materials and Supplies	51.5		46.2
Total Inventories		$80.5		$59.3


(a)	Fuel inventory was lower at December 31, 2013 primarily due to 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 the effects of certain types of regulation. 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. We expect to retire Taconite Harbor Unit 3 and convert Laskin to natural gas in the second quarter of 2015, which were included in our 2013 Integrated Resource Plan approved by the MPUC in a November 2013 order. Accordingly, we do not expect any impairment charge as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin.

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 2014 asset management and disposition plan (Plan) which is 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. Our analysis assumes retail land sales are followed by project bulk sales over a five-year period. 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 2014, 2013 and 2012, 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 years ended December 31, 2014, 2013, and 2012.

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.)



Prepayments and Other Current Assets
As of December 31	2014		2013
Millions
Deferred Fuel Adjustment Clause		$16.3		$23.0
Construction Costs for Development Project (a)	48.2		—
Restricted Cash (b)	2.7		—
Other	14.8		12.1
Total Prepayments and Other Current Assets		$82.0		$35.1


(a)	Construction Costs for Development Project acquired/incurred due to ALLETE Clean Energy’s acquisition on November 20, 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 7. Acquisitions.)


(b)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets. As of December 31, 2014, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $5.3 million related to ALLETE Clean Energy’s wind energy facilities debt service and other requirements. As of December 31, 2013, the Company had restricted cash of $5.4 million related to cash held in escrow pending the closing of the wind energy facilities acquisition on January 30, 2014. (See Note 7. Acquisitions.)



Other Current Liabilities
As of December 31	2014		2013
Millions
Customer Deposits		$19.7		$26.0
Power Purchase Agreements (a)	19.4		—
Construction Deposits Received for Development Project (b)	54.3		—
Other	27.4		26.6
Total Other Current Liabilities		$120.8		$52.6


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)


(b)	Construction Deposits Received for Development Project are due to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayment and Other Current Assets table and Note 7. Acquisitions.)



Other Non-Current Liabilities
As of December 31	2014		2013
Millions
Asset Retirement Obligation (a)		$109.2		$81.8
Power Purchase Agreements (b)	110.7		—
Other	45.1		45.4
Total Other Non-Current Liabilities		$265.0		$127.2


(a)	The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.


(b)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)

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 becomes 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.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

Amortization of Power Purchase Agreements. As part of the ALLETE Clean Energy wind energy facilities acquisitions in 2014, the Company assumed various PPAs that were at below-market prices and will amortize the liabilities to revenue over the life of the agreements for the difference between contract prices and estimated market prices. In 2014, we recognized $12.7 million of amortization relating to the PPA liabilities in Operating Revenue on the Consolidated Statement of Income.

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 as well as 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.

Purchase Accounting. In accordance with the authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the balance sheet if it exceeds the estimated fair value and as a bargain purchase gain on the income statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. (See Note 7. Acquisitions.)

New Accounting Standards.

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 an NOL carryforward, a similar tax loss, or a tax credit carryforward. To the extent an NOL 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 was adopted in the first quarter of 2014, and did not have a material impact on our consolidated financial position, results of operations, or cash flows.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. In April 2014, the FASB issued an accounting standard update modifying the criteria for determining which disposals should be presented as discontinued operations and modifying the related disclosure requirements. Additionally, the new guidance requires that a business which qualifies as held for sale upon acquisition should be reported as discontinued operations. The new guidance will be effective beginning in the first quarter of 2015, and will apply prospectively to new disposals and new classifications of disposal groups as held for sale. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

Revenue from Contracts with Customers. In May 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This accounting guidance is effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. Early adoption is not permitted for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s consolidated financial statements.

Business Segments

12 Months Ended

Dec. 31, 2014

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 our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, 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
Year Ended December 31, 2014
Operating Revenue		$1,136.8			$1,003.5			$133.3
Fuel and Purchased Power Expense	356.1			356.1			—
Operating and Maintenance Expense	456.2			345.6			110.6
Depreciation Expense	135.7			118.0			17.7
Operating Income	188.8			183.8			5.0
Interest Expense	(54.8		)	(46.9		)	(7.9		)
Equity Earnings in ATC	19.6			19.6			—
Other Income	8.6			7.8			0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	162.2			164.3			(2.1		)
Income Tax Expense (Benefit)	36.7			39.9			(3.2		)
Net Income	125.5			124.4			1.1
Less: Non-Controlling Interest in Subsidiaries	0.7			—			0.7
Net Income Attributable to ALLETE		$124.8			$124.4			$0.4

As of December 31, 2014
Total Assets		$4,360.8			$3,709.6			$651.2
Capital Additions		$604.3			$583.5			$20.8

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
Year Ended December 31, 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 Non-Controlling Interest and 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		)
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income (Loss) Attributable to ALLETE		$104.7			$104.9		$(0.2)

As of December 31, 2013
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
Year Ended December 31, 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 Non-Controlling Interest and 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
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$97.1			$96.1		$1.0

As of December 31, 2012
Total Assets		$3,253.4			$2,962.4			$291.0
Capital Additions		$432.2			$418.2			$14.0

- 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, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

PROPERTY, PLANT AND EQUIPMENT



Property, Plant and Equipment
As of December 31	2014			2013
Millions
Regulated Utility		$3,903.3			$3,380.0
Construction Work in Progress	355.4			303.9
Accumulated Depreciation	(1,260.2		)	(1,181.7		)
Regulated Utility Plant - Net	2,998.5			2,502.2
Investments and Other Operations (a)	357.8			131.3
Construction Work in Progress	5.9			3.4
Accumulated Depreciation	(75.8		)	(60.4		)
Investments and Other Operations Plant - Net	287.9			74.3
Property, Plant and Equipment - Net		$3,286.4			$2,576.5


(a)	Includes primarily ALLETE Clean Energy, BNI Coal and a small amount of non-rate base generation.

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 50 years	Distribution	18 to 65 years
Transmission	44 to 67 years	Investments and Other Operations	5 to 44 years

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, development 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, 2012		$77.9
Accretion	4.6
Revisions in estimated cash flows	(0.7		)
Obligation as of December 31, 2013	81.8
Accretion	5.5
Liabilities recognized (a)	23.0
Liabilities settled	(0.5		)
Revisions in estimated cash flows	(0.6		)
Obligation as of December 31, 2014		$109.2


(a)	The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.

- 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, 2014

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 one CapX2020 project and have completed two CapX2020 projects with varying ownership percentages.

Our investments in jointly-owned facilities and projects and the related ownership percentages are as follows:



Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
2014
Boswell Unit 4		$419.1		$209.1		$168.1	80
CapX2020 Projects	55.5		1.7		44.0		9.3 - 14.7
Total		$474.6		$210.8		$212.1
2013
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, 2014

Regulatory Matters [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

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

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

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements 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 agreement, no termination notice may be given prior to June 30, 2023. Under the agreements with the remaining 15 municipal customers and SWL&P, 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 allows 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. In November 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 filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015. (See Note 1. Operations and Significant Accounting Policies.)

NOTE 5. REGULATORY MATTERS (Continued)

Renewable Cost Recovery Rider. Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

On January 29, 2015, the MPUC approved our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider. The total project investment for Thomson is estimated to be approximately $90 million, net of insurance. (See Note 12. Commitments, Guarantees and Contingencies.)

Integrated Resource Plan. In a November 2013 order, 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 which were completed in the fourth quarter of 2014, installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 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 proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act 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 $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 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 was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills. (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 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 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 the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. (See Note 12. Commitments, Guarantees and Contingencies.)

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. 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 regulatory authority or over the corresponding period related to the asset or liability.

NOTE 5. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2014		2013
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$16.3		$23.0
Total Current Regulatory Assets	16.3		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	223.9		164.1
Cost Recovery Riders (c)	59.7		39.6
Income Taxes	46.6		35.3
Asset Retirement Obligations	17.8		16.0
PPACA Income Tax Deferral	5.0		5.0
Other	4.3		3.8
Total Non-Current Regulatory Assets	357.3		263.8
Total Regulatory Assets		$373.6		$286.8

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$42.9		$19.7
Plant Removal Obligations	22.8		19.7
Income Taxes	13.4		17.0
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	3.5		16.3
Other	11.6		8.3
Total Non-Current Regulatory Liabilities		$94.2		$81.0


(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 the Consolidated Balance Sheet. (See Note 17. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are due to capital expenditures related to our Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC

12 Months Ended

Dec. 31, 2014

Investment in ATC [Abstract]

Investment in ATC [Text Block]

INVESTMENT IN ATC

Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC rates are based on a FERC-approved 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, 2014, our equity investment in ATC was $121.1 million ($114.6 million at December 31, 2013). On January 29, 2015, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $1.9 million throughout 2015.



ALLETE’s Investment in ATC
Year Ended December 31	2014			2013
Millions
Equity Investment Beginning Balance		$114.6			$107.3
Cash Investments	3.9			3.1
Equity in ATC Earnings	19.6			20.3
Distributed ATC Earnings	(17.0		)	(16.1		)
Equity Investment Ending Balance		$121.1			$114.6

NOTE 6. INVESTMENT IN ATC (Continued)



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2014		2013
Millions
Current Assets		$66.4		$80.7
Non-Current Assets	3,728.7		3,509.5
Total Assets		$3,795.1		$3,590.2
Current Liabilities		$313.1		$381.4
Long-Term Debt	1,701.0		1,550.0
Other Non-Current Liabilities	163.8		126.2
Members’ Equity	1,617.2		1,532.6
Total Liabilities and Members’ Equity		$3,795.1		$3,590.2



Income Statement Data
Year Ended December 31	2014		2013		2012
Millions
Revenue		$635.0		$626.3		$603.2
Operating Expense	307.4		295.1		281.0
Other Expense	88.9		83.6		84.8
Net Income		$238.7		$247.6		$237.4
ALLETE’s Equity in Net Income		$19.6		$20.3		$19.4

In November 2013, several customer groups located within the MISO service area filed a complaint with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. ATC's current authorized return on equity is 12.2 percent. In the fourth quarter of 2014, FERC ordered formal hearing proceedings to begin and established a date for potential refunds from November 12, 2013. An initial decision in the complaint is expected by November 30, 2015. In the fourth quarter of 2014, ATC recorded approximately an $18 million refund liability as ATC believes that it is probable that a refund will be required upon ultimate resolution of this matter. The refund liability is subject to adjustment in future periods if assumptions in the estimate change. ATC’s refund liability negatively impacted our Equity Earnings in ATC by approximately $1 million after-tax in 2014. We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million on an after-tax basis.

- 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

Dec. 31, 2014

Acquisitions [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.

ACE Wind Acquisition

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) from The AES Corporation (AES) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

Lake Benton, Storm Lake II and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake II began commercial operations in 1998, 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 in June 2015. Armenia Mountain began operations in 2009.

NOTE 7. ACQUISITIONS (Continued)

ALLETE Clean Energy acquired a controlling interest in the limited liability company (LLC) which owns Lake Benton and Storm Lake II, and a controlling interest in the LLC that owns Condon. The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. In connection with finalizing purchase price accounting, the Company recorded minor adjustments to certain assets and liabilities, which are reflected in the table below. These adjustments had no impact on the results of operations. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	14.3
Property, Plant and Equipment – Net	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
Other Current Liabilities (b)		$15.2
Long-Term Debt Due Within One Year	2.2
Long-Term Debt	21.1
Power Purchase Agreements	99.4
Other Non-Current Liabilities	10.6
Non-Controlling Interest (c)	7.1
Total Liabilities and Non-Controlling Interest Assumed	$155.6
Net Identifiable Assets Acquired		$26.9


(a)	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.


(c)	The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.

ALLETE Clean Energy incurred $1.4 million after-tax of acquisition-related costs in 2014, which were expensed when incurred and were recorded in Other Expense on the Consolidated Statement of Income. The pro forma impact of this acquisition was not material to the results of the Company for the years ended December 31, 2014 and 2013.

On February 11, 2014, ALLETE Clean Energy purchased the non-controlling interest related to Lake Benton and Storm Lake II for $6.0 million. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income.

Montana-Dakota Utilities

On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. Fair value measurements were valued primarily using the replacement cost method and determined that the assets acquired amounted to cash of approximately $3.6 million and construction in process of approximately $23.4 million. There were no liabilities assumed and no recognition of goodwill.

Acquisition-related costs were expensed as incurred and were not material for the year ended December 31, 2014. The pro forma impacts of this acquisition also were not material to the results of the Company for the years ended December 31, 2014 and 2013.

NOTE 7. ACQUISITIONS (Continued)

As of December 31, 2014, $48.2 million of construction costs incurred (including the construction costs acquired) and $54.3 million of construction deposits received from Montana-Dakota Utilities Co. have been classified on the Consolidated Balance Sheet as Other Current Assets and Other Current Liabilities, respectively. Subject to regulatory approval, ALLETE expects revenue to be recognized under the percentage of completion method of accounting as progress toward completion of the project is achieved. Until regulatory approval is obtained, we expect no impact from the project on the Consolidated Statement of Income. Costs to construct the wind facility and deposits received from Montana-Dakota Utilities Co. are reported as Construction Costs for Development Project in investing activities and Construction Deposits Received for Development Project in financing activities on the Consolidated Statement of Cash Flows, respectively.

Storm Lake I Acquisition

On December 17, 2014, ALLETE Clean Energy acquired a wind generation facility in Storm Lake, Iowa (Storm Lake I) from NRG Energy, Inc. for $15.0 million, subject to a working capital adjustment.

Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which ALLETE Clean Energy acquired in January 2014. The wind generation facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and liabilities assumed at the date of acquisition, as shown in the table below. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relating primarily to property, plant and equipment and the PPA; subsequent adjustments could impact the amount of goodwill recorded or result in a bargain purchase. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment – Net	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Other Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
Other Non-Current Liabilities	17.0
Total Liabilities Assumed	$48.7
Net Identifiable Assets Acquired		$15.1


(a)	Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.

ALLETE Clean Energy Purchase Agreement

On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million, subject to a working capital adjustment.

The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.

- 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, 2014

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At December 31, 2014, our 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.



Other Investments
As of December 31	2014		2013
Millions
ALLETE Properties		$88.2		$89.9
Available-for-sale Securities (a)	18.9		17.7
Cash Equivalents (b)	2.9		34.2
Other	4.4		4.5
Total Other Investments		$114.4		$146.3


(a)	As of December 31, 2014, 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 $1.7 million, in three years to less than five years was $2.6 million, and in five or more years was $5.9 million.


(b)	During 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.



ALLETE Properties
As of December 31	2014			2013
Millions
Land Inventory Beginning Balance		$85.4			$86.5
Cost of Sales	(2.2		)	(1.5		)
Other	0.6			0.4
Land Inventory Ending Balance	83.8			85.4
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.2			1.4
Other	3.2			3.1
Total Real Estate Assets		$88.2			$89.9

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 indicators of impairment on a quarterly basis and no impairments were recorded for the year ended December 31, 2014 (none for the years ended December 31, 2013 and 2012).

Long-Term Finance Receivables. As of December 31, 2014, long-term finance receivables were $1.2 million net of an allowance ($1.4 million net of an allowance as of December 31, 2013). 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, 2014, the allowance for doubtful accounts amounted to $0.6 million ($0.6 million as of December 31, 2013).

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 held in other postretirement plans to fund employee benefits.

NOTE 8. INVESTMENTS (Continued)



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
2012	$27.4	$0.5	$1.1	$26.8
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—
2012		$1.5	—	—

Derivatives	12 Months Ended
Derivatives	Dec. 31, 2014
Derivatives [Abstract]
Derivatives [Text Block]	DERIVATIVES We have one variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million term loan which represents approximately 5 percent of the Company’s outstanding long-term debt, including long-term debt due within one year, as of December 31, 2014. (See Note 11. Short-Term and Long-Term Debt.) The Swap has an effective date of August 26, 2014, and matures on August 25, 2015. The Swap involves the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreement at 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swap are expected to be highly effective. If it is determined that the Swap ceases 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 assessment of hedge effectiveness resulted in no ineffectiveness recorded for the year ended December 31, 2014. As of December 31, 2014, the fair value of the Swap was a $0.3 million liability which was included in Other Current Liabilities on the Consolidated Balance Sheet. The fair value as of December 31, 2013, included an additional variable to fixed interest rate swap that expired on August 26, 2014, with an aggregate fair value at December 31, 2013 of $0.6 million of which $0.3 million was included in Other Non-Current Liabilities and $0.3 million was included in Other Current Liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swap were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swap 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 Swap will be recorded in earnings when the hedged transactions occurs or when it is probable it will not occur. Gains or losses on the interest rate hedging transaction 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, 2014

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.

NOTE 10. FAIR VALUE (Continued)

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.

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, 2014 and 2013. 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 these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the tables below.



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.1	—		—		$8.1
Available-for-sale – Corporate Debt Securities	—			$10.8	—	10.8
Cash Equivalents	2.9		—		—	2.9
Total Fair Value of Assets		$11.0		$10.8	—		$21.8

Liabilities:
Deferred Compensation (b)	—			$16.2	—		$16.2
Derivatives – Interest Rate Swap (c)	—		0.3		—	0.3
Total Fair Value of Liabilities	—			$16.5	—		$16.5
Total Net Fair Value of Assets (Liabilities)		$11.0	$(5.7)		—		$5.3


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.


(c)	Included in Current Liabilities - Other on the Consolidated Balance Sheet.

NOTE 10. FAIR VALUE (Continued)



	Fair Value as of December 31, 2013
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.9	—		—		$7.9
Available-for-sale – 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 (b)	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap (c)	—		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


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.


(c)	Included in Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.

There was no activity in Level 3 during the years ended December 31, 2014 or 2013.

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, 2014 and 2013, there were no transfers in or out of Levels 1, 2 or 3.

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



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2014	$1,373.5	$1,484.5
December 31, 2013	$1,110.2	$1,131.7

- 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.

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Short-term and Long-term Debt

12 Months Ended

Dec. 31, 2014

Short-Term and Long-Term Debt [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2014, total short-term debt outstanding was $104.4 million ($27.2 million as of December 31, 2013) and consisted of long-term debt due within one year and notes payable.

As of December 31, 2014, we had bank lines of credit aggregating $408.4 million ($406.4 million as of December 31, 2013), the majority of which expire in November 2018. We had $47.5 million outstanding in standby letters of credit and $3.7 million outstanding in draws under our lines of credit as of December 31, 2014 ($5.4 million in standby letters of credit and no draws outstanding as of December 31, 2013).

Long-Term Debt. As of December 31, 2014, total long-term debt outstanding was $1,272.8 million ($1,083.0 million as of December 31, 2013). In conjunction with ALLETE Clean Energy’s January 30, 2014 wind energy facilities acquisition, ALLETE Clean Energy assumed $23.3 million of long-term debt, including $2.2 million due within one year. (See Note 7. Acquisitions.) The aggregate amount of long-term debt maturing in 2015 is $100.7 million ($24.9 million in 2016; $54.6 million in 2017; $54.8 million in 2018; $46.9 million in 2019; and $1,091.6 million thereafter). Substantially all of our regulated 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.

During 2014, we issued $375.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:



Issue Date	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%
September 16, 2014	September 15, 2021	$60 Million	3.02%
September 16, 2014	September 15, 2029	$50 Million	3.74%
September 16, 2014	September 15, 2044	$50 Million	4.39%

The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision; however, each series of bonds is redeemable at par, including, in each case, accrued and unpaid interest, six months prior to the maturity date. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company used the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures 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 institutional accredited investors.

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



Long-Term Debt
As of December 31	2014		2013
Millions
First Mortgage Bonds
6.94% Series Due 2014	—		$18.0
7.70% Series Due 2016	$20.0		20.0
1.83% Series Due 2018	50.0		50.0
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
3.02% Series Due 2021	60.0		—
3.40% Series Due 2022	75.0		—
4.95% Pollution Control Series F Due 2022	—		111.0
6.02% Series Due 2023	75.0		75.0
3.69% Series Due 2024	60.0		—
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		40.0
3.74% Series Due 2029	50.0		—
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		60.0
4.95% Series Due 2044	40.0		—
5.05% Series Due 2044	40.0		—
4.39% Series Due 2044	50.0		—
Unsecured Term Loan Variable Rate Due 2015	75.0		75.0
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020	24.6		24.6
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8		27.8
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		15.0
Other Long-Term Debt, 0.08% – 7.50% Due 2015 – 2037	59.1		41.8
Total Long-Term Debt	1,373.5		1,110.2
Less: Due Within One Year	100.7		27.2
Net Long-Term Debt		$1,272.8		$1,083.0

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 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, 2014, our ratio was approximately 0.47 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from 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, 2014, 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.

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Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2014

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 Agreement, 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, 2014, Square Butte had total debt outstanding of $402.9 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2015 through 2019, 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 2014 was $70.1 million ($71.1 million in 2013; $67.1 million in 2012). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $10.5 million in 2014 ($10.5 million in 2013; $11.1 million in 2012). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, Minnesota Power is selling 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.

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 from 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. 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 that expire in 2031 and 2032, respectively. Each agreement 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 2020. 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. In addition, 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 provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro 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. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

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.

Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates 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 Thomson, which had damage to the forebay canal and flooding at the facility. The forebay rebuild is complete and Minnesota Power commenced filling the forebay canal on October 9, 2014. Thomson returned to partial generation in the fourth quarter of 2014 and work is ongoing towards returning to full generation early in 2015. Total project costs are estimated to be approximately $90 million, net of insurance. On January 29, 2015, the MPUC approved our petition seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

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 December 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2015. Minnesota Power is currently 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 $38.3 million for 2015. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Coal, Rail and Shipping Contracts (Continued)

Rail congestion has negatively impacted customers throughout the Upper Midwest, affecting commerce by rail including, but not limited to, agriculture, commodity, intermodal and energy industries. We have experienced delays in coal deliveries resulting in lower coal inventory levels in 2013 and throughout much of 2014 at our generating stations in Northeastern Minnesota. Minnesota Power filed a notice of fuel supply emergency with the U.S. Department of Energy on September 22, 2014 in response to inadequate rail deliveries. Rail deliveries increased late in 2014, building inventories to normal levels by year end 2014. On December 30, 2014, the Surface Transportation Board ordered BNSF Railway to submit a detailed description of the contingency plans it would use to mitigate an acute coal inventory shortage at one or more generating stations in a region. Minnesota Power’s exposure to price risk for purchased power is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates.

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 2022. The aggregate amount of minimum lease payments for all operating leases is $13.4 million in 2015, $11.4 million in 2016, $10.6 million in 2017, $9.5 million in 2018, $8.3 million in 2019 and $27.3 million thereafter. Total lease expense was $14.8 million in 2014 ($13.8 million in 2013; $11.5 million in 2012).

Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other 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. In November 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 filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015.

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 and 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.

Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, of which the final phase is currently under construction and expected to be in service in the second quarter of 2015.

Based on projected costs of the three transmission line projects and the allocation agreements among participating utilities, in total Minnesota Power plans to invest approximately $105 million in the CapX2020 initiative through 2015, of which $99 million was spent through December 31, 2014. 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 220-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.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

The GNTL is subject to various federal and state regulatory approvals. In October 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 the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.

Environmental Matters

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

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

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information becomes 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, baghouses 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 asserted 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 reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota (Court) on September 29, 2014. The Consent Decree covers Minnesota Power’s Boswell, Laskin, Taconite Harbor, and Rapids Energy Centers. The Consent Decree provides for more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at some units, and the addition of 200 MW of wind energy. Minnesota Power is required to spend $4.2 million on environmental mitigation projects over the next five years. Under the terms of the Consent Decree, Minnesota Power also paid a $1.4 million civil penalty which was recognized as an expense in 2013. In 2014, the Company recorded an expense associated with the environmental mitigation projects.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Since 2005, the Company has, and will, invest more than $600 million to reduce sulfur dioxide, nitrogen oxide, mercury and particulate matters emissions at its thermal generation facilities, and between 2010 and 2014 placed in service nearly 500 MW of renewable wind energy, which fulfills certain obligations under the Consent Decree. In addition, Minnesota Power’s EnergyForward plan addresses many of the requirements included in the Consent Decree. Under the EnergyForward plan, Minnesota Power intends to: 1) retire Taconite Harbor Unit 3, 2) convert Laskin from coal to natural gas, and 3) install emission controls at Boswell Unit 4.

The Consent Decree further requires that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted to an existing Boswell scrubber. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. We are evaluating our options with regard to Boswell Units 1 and 2 to comply with the Consent Decree and future anticipated environmental regulations. We are required to notify the EPA no later than December 31, 2016, whether we will retire, refuel, repower or reroute Boswell Units 1 and 2. We believe that future capital expenditures or costs to retire would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). On April 29, 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit on June 26, 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017.

CSAPR requires five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NO_x reductions under the CSAPR ozone season control program. CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances will be allocated to facilities from each state’s annual budget and can be bought and sold.

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NO_x and SO₂ Phase I allowances already issued, and our review of the CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be in compliance in both Phase I and Phase II.

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, built 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. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC in November 2013, we plan to retire Taconite Harbor Unit 3 in the second quarter of 2015. We believe that the Taconite Harbor Unit 3 retirement will be accomplished before any compliance deadline takes effect.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 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 $250 million through 2016, of which $145 million was spent through December 31, 2014. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, 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 to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year.

Minnesota Mercury Emissions Reduction Act. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power must implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above, which is required to be completed by April 1, 2016 (see Mercury and Air Toxics Standards (MATS) Rule), will fulfill the requirements of the Minnesota Mercury Emissions Reduction Act.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT) 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.

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. On November 25, 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time.

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM_2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. 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_2.5 standard. To implement the new annual PM_2.5 standard, the EPA is also revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data. The EPA issued designations of 2012 fine particulate attainment status on December 18, 2014. Minnesota retained 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. In April 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. 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 EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. 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.

In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have applied for and received Class I status. A public hearing was held by the Band on October 2, 2014, and the public comment period on the petition expired on November 10, 2014. The Band is now preparing responses to the comments after which the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. We are unable to determine the impact of potential Class I status on the Company’s operations at this time.

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which 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. In June 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.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the 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 June 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established lower permitting thresholds for GHG than for other pollutants subject to PSD. However, the court also upheld the EPA’s power to require BACT for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions. At this time, we are unable to predict the compliance costs that we might incur.

In March 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS), under Section 111(b) of the Clean Air Act, 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. In September 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO₂ emissions.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units” (CPP). The EPA is expected to finalize such rules by the summer of 2015. In the CPP, the EPA proposes to set state-specific goals for CO₂ emissions from the power sector. The EPA maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions (BSER).

The EPA proposed that BSER is comprised of four building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers.

The EPA then established state goals, expressed as a carbon intensity target in CO₂ tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA.

Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its “EnergyForward” strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 5. Regulatory Matters.)

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.

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Minnesota’s Next Generation Energy Act of 2007. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO₂-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO₂ emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit on May 16, 2014.

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 impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was published in the Federal Register on August 15, 2014, with an effective date of October 14, 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDEC permits have been re-issued containing 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. We would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In April 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. 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 in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, 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 (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).

NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

The EPA issued the final CCR rule on December 19, 2014 under Subtitle D (non-hazardous) of RCRA. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case.

Other Matters

ALLETE Clean Energy. In January 2014, ALLETE Clean Energy acquired three wind energy facilities–Lake Benton, Storm Lake II and Condon–from AES. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. On December 17, 2014, ALLETE Clean Energy acquired a wind facility, Storm Lake I, which has a PPA in place for its entire output which expires in 2018. On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire a wind facility in southern Minnesota and has PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015. (See Note 7. Acquisitions.)

BNI Coal. As of December 31, 2014, BNI Coal had surety bonds outstanding of $49.5 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 for an additional $0.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $49.3 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, 2014, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in November 2006 for Town Center and November 2007 for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, 2014, we owned 72 percent of the assessable land in the Town Center District (73 percent at December 31, 2013) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2013). 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.

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, which it supplemented in March 2014. 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, 2014, 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, 2014

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, 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
Employee Stock Purchase Program	18	0.8
Invest Direct	378	18.9
Options and Stock Awards	78	8.0
Equity Issuance Program	1,851	90.0
Forward Sale Agreement and Issuance	1,807	85.2
Contributions to Pension	396	19.5
Balance as of December 31, 2014	45,929		$1,107.6

Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc., in February 2008, as amended most recently in May 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 1.3 million shares remain available for issuance. For the year ended December 31, 2014, 1.9 million shares of common stock were issued under this agreement resulting in net proceeds of $90.0 million (1.3 million shares for net proceeds of $63.4 million for the year ended December 31, 2013). The shares sold in 2012 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, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). In 2014 and 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, there were 0.2 million shares excluded because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.

Forward Sale Agreement and Issuance of Common Stock. On February 26, 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with our capital investment strategy.

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock (borrowed shares) from third parties and sold them to the underwriters. ALLETE had the right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elected physical settlement of the Agreement, it would deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price was initially $48.01 per share, subject to adjustment as provided in the Agreement. On September 5, 2014, ALLETE physically settled a portion of its obligations under the Agreement by having delivered approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million. On February 4, 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares for cash proceeds of $65.4 million.

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

In connection with the public offering of the 2.8 million shares, ALLETE granted the underwriters an option to purchase up to an additional 0.4 million shares of ALLETE common stock (the option shares). The underwriters exercised the option in full and on March 4, 2014, the Company issued and sold the option shares to the underwriters at a price to ALLETE equal to the initial forward sale price for proceeds of $20.2 million.

The equity forward transaction was reflected in ALLETE’s diluted earnings per share using the treasury stock method, which resulted in no material dilutive impact to ALLETE’s diluted earnings per share for the year ended December 31, 2014. Prior to any settlement date, any dilutive effect of the Agreement on our earnings per share would only occur during periods when the average market price per share of our common stock is above the per share adjusted forward sales price described above.

The equity forward transaction is accounted for as an equity instrument in accordance with the accounting guidance for distinguishing liabilities from equity and the guidance for derivatives. Under the accounting guidance, the transaction qualifies for an exception from derivative accounting because the forward sale transaction is indexed to ALLETE’s stock.

Contributions to Pension. In 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. 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, as amended.



Reconciliation of Basic and Diluted
Earnings Per Share			Dilutive
Year Ended December 31	Basic		Securities	Diluted
Millions Except Per Share Amounts
2014
Net Income Attributable to ALLETE		$124.8			$124.8
Average Common Shares	42.9		0.2	43.1
Earnings Per Share		$2.91			$2.90
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

- Definition

The entire disclosure for earnings per share.

+ References+ Details

Income Tax Expense

12 Months Ended

Dec. 31, 2014

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



Income Tax Expense
Year Ended December 31	2014			2013			2012
Millions
Current Tax Expense
Federal (a)	$1.1			—			—
State (a)	2.9			$0.1			$0.5
Total Current Tax Expense	4.0			0.1			0.5
Deferred Tax Expense
Federal	25.3			22.9			37.0
State	8.2			6.5			1.4
Investment Tax Credit Amortization	(0.8		)	(0.8		)	(0.9		)
Total Deferred Tax Expense	32.7			28.6			37.5
Total Income Tax Expense		$36.7			$28.7			$38.0

(a)

For the years ended December 31, 2014, 2013, and 2012, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. The federal and state NOLs will be carried forward to offset future taxable income. The year ended 2014 includes the resolution of an IRS examination for the tax years 2005-2009 and the impacts of initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired.



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Year Ended December 31	2014			2013			2012
Millions
Income Before Non-Controlling Interest and Income Taxes		$162.2			$133.4			$135.1
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$56.8			$46.7			$47.3
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	7.2			4.3			1.2
Regulatory Differences for Utility Plant	(3.5		)	(2.2		)	(2.2		)
Production Tax Credits	(23.7		)	(19.2		)	(7.6		)
Other	(0.1		)	(0.9		)	(0.7		)
Total Income Tax Expense		$36.7			$28.7			$38.0

The effective tax rate on income was 22.6 percent for 2014 (21.5 percent for 2013; 28.1 percent for 2012). The 2014, 2013, and 2012 effective rates were primarily impacted by production tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above).

NOTE 15. INCOME TAX EXPENSE (Continued)



Deferred Tax Assets and Liabilities
As of December 31	2014			2013
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$102.2			$66.3
Property Related	102.7			82.2
NOL Carryforwards	156.5			112.8
Tax Credit Carryforwards	95.7			55.1
Power Purchase Agreements	51.8			—
Other	17.0			16.9
Gross Deferred Tax Assets	525.9			333.3
Deferred Tax Asset Valuation Allowance	(22.1		)	(8.0		)
Total Deferred Tax Assets		$503.8			$325.3
Deferred Tax Liabilities
Property Related		$848.8			$656.2
Regulatory Asset for Benefit Obligations	89.9			58.7
Unamortized Investment Tax Credits	10.3			11.1
Partnership Basis Differences	41.9			36.7
Other	16.1			22.7
Total Deferred Tax Liabilities		$1,007.0			$785.4
Net Deferred Income Taxes		$503.2			$460.1
Recorded as:
Net Current Deferred Tax Assets		$7.5		$19.0
Net Long-Term Deferred Tax Liabilities	510.7			479.1
Net Deferred Income Taxes		$503.2			$460.1



NOL and Tax Credit Carryforwards
As of December 31	2014	2013
Millions
Federal NOL Carryforwards (a)	$413.7		$279.8
Federal Tax Credit Carryforwards	$59.3	$35.5
State NOL Carryforwards (a)	$184.7	$156.3
State Tax Credit Carryforwards (b)	$14.7	$11.9


(a)	Pretax amounts.


(b)	Net of a $21.7 million valuation allowance as of December 31, 2014 ($7.7 million as of December 31, 2013).

The federal NOL and tax credit carryforward periods expire between 2030 and 2035. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore no federal valuation allowance has been recognized as of December 31, 2014. The state NOL and tax credit carryforward periods expire between 2025 and 2035. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.

NOTE 15. INCOME TAX EXPENSE (Continued)



Gross Unrecognized Income Tax Benefits	2014			2013			2012
Millions
Balance at January 1		$1.2			$2.7			$11.4
Additions for Tax Positions Related to the Current Year	—			0.1			—
Additions for Tax Positions Related to Prior Years	1.0			1.3			—
Reductions for Tax Positions Related to Prior Years	—			—			(8.7		)
Reductions for Settlements	—			(2.9		)	—
Lapse of Statute	(0.2		)	—			—
Balance as of December 31		$2.0			$1.2			$2.7

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, 2014, include $0.4 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, 2014, we had no accrued interest ($0.5 million for 2013 and $0.5 million for 2012) related to unrecognized tax benefits included on our Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on our Consolidated Statement of Income. In 2014, we recognized a decrease in interest expense of $0.5 million related to unrecognized tax benefits on our Consolidated Statement of Income (zero for 2013 and decrease of $0.6 million for 2012). There were no penalties recognized in 2014, 2013 or 2012. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on our Consolidated Balance Sheet.

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 examination for years before 2011, or state examination for years before 2010.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $0.1 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, 2014

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, 2014, 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, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)		$(0.3)	$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.3	)	(5.2	)	0.2	(5.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	0.1		1.2		—	1.3
Net Other Comprehensive Income (Loss)	(0.2	)	(4.0	)	0.2	(4.0	)
Ending Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)		$(0.1)	$(21.1)

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2014, were as follows:



	Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	December 31,
	2014
Millions
Unrealized Gains on Available-for-sale Securities (a)	$(0.2)
Income Taxes (b)	0.1
Total, Net of Income Taxes	$(0.1)

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.3
Actuarial Gains and Losses (c)	(2.3	)
Total	(2.0	)
Income Taxes (b)	0.8
Total, Net of Income Taxes	$(1.2)
Total Reclassifications	$(1.3)


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


(b)	Included in Income Tax Expense on our 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.)

NOTE 16. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

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 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 our Consolidated Statement of Income.


(b)	Included in Income Tax Expense on our 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, 2014

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. In 2014, we contributed $19.5 million to the plans, all of which was contributed in shares of ALLETE common stock (no contributions in 2013; $7.3 million in 2012). We also have a defined contribution RSOP covering substantially all employees. The 2014 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $9.1 million ($8.4 million for the 2013 plan year; $7.7 million for the 2012 plan year). (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. In 2014, our postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015. The postretirement health and life plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In 2014, no contributions were made to the VEBAs ($10.8 million in 2013; $1.5 million in 2012) and no contributions were made to the grantor trusts ($2.0 million in 2013; none in 2012).

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 contributions to the defined benefit pension plan or the defined benefit postretirement health and life plan in 2015.

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
At December 31	2014			2013
Millions
Accumulated Benefit Obligation		$661.4			$577.6
Change in Benefit Obligation
Obligation, Beginning of Year		$622.8			$652.1
Service Cost	8.3			9.9
Interest Cost	29.8			26.0
Actuarial (Gain) Loss	72.6			(49.2		)
Benefits Paid	(36.9		)	(33.5		)
Participant Contributions	17.9			17.5
Obligation, End of Year		$714.5			$622.8
Change in Plan Assets
Fair Value, Beginning of Year		$501.6			$460.1
Actual Return on Plan Assets	41.0			56.5
Employer Contribution (a)	38.5			18.5
Benefits Paid	(36.9		)	(33.5		)
Fair Value, End of Year		$544.2			$501.6
Funded Status, End of Year	$(170.3)			$(121.2)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.2)			$(1.1)
Non-Current Liabilities	$(169.1)			$(120.1)


(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
As of December 31	2014		2013
Millions
Net Loss		$250.4		$194.9
Prior Service Cost	0.2		0.4
Total Unrecognized Pension Costs		$250.6		$195.3



Components of Net Periodic Pension Expense
Year Ended December 31	2014			2013			2012
Millions
Service Cost		$8.3			$9.9			$9.1
Interest Cost	29.8			26.0			26.4
Expected Return on Plan Assets	(38.2		)	(35.2		)	(35.4		)
Amortization of Loss	14.2			21.5			17.5
Amortization of Prior Service Cost	0.3			0.3			0.3
Net Pension Expense		$14.4			$22.5			$17.9

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 or Liabilities
Year Ended December 31	2014		2013
Millions
Net (Gain) Loss	$69.8		$(70.4)
Amortization of Prior Service Cost	(0.3	)	(0.3	)
Amortization of Loss	(14.2	)	(21.5	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$55.3		$(92.2)



Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31	2014		2013
Millions
Projected Benefit Obligation		$714.5		$622.8
Accumulated Benefit Obligation		$661.4		$577.6
Fair Value of Plan Assets		$544.2		$501.6



Postretirement Health and Life Obligation and Funded Status
At December 31	2014			2013
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$151.9			$168.8
Service Cost	3.4			3.9
Interest Cost	7.3			6.8
Actuarial (Gain) Loss	18.1			(18.8		)
Benefits Paid	(8.9		)	(9.9		)
Participant Contributions	2.6			2.7
Plan Amendments	(2.9		)	—
Plan Curtailments	(0.6		)	—
Settlements (a)	—			(1.6		)
Obligation, End of Year		$170.9			$151.9
Change in Plan Assets
Fair Value, Beginning of Year		$157.0			$131.0
Actual Return on Plan Assets	11.6			21.4
Employer Contribution	1.1			11.7
Participant Contributions	2.6			2.7
Benefits Paid	(9.1		)	(9.8		)
Fair Value, End of Year		$163.2			$157.0
Funded Status, End of Year	$(7.7)			$5.1

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$6.6			$19.4
Current Liabilities	$(0.9)			$(0.9)
Non-Current Liabilities	$(13.4)			$(13.4)


(a)	Result of the termination of 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 $17.9 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2014 ($17.8 million at December 31, 2013).

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
As of December 31	2014		2013
Millions
Net (Gain) Loss	$6.9		$(9.0)
Prior Service Credit	(10.6	)	(10.1	)
Total Unrecognized Postretirement Health and Life Credit	$(3.7)		$(19.1)



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2014			2013			2012
Millions
Service Cost		$3.4			$3.9			$4.2
Interest Cost	7.3			6.8			9.4
Expected Return on Plan Assets	(10.3		)	(9.7		)	(9.9		)
Amortization of Loss	0.5			1.6			7.5
Amortization of Prior Service Credit	(2.5		)	(2.5		)	(1.7		)
Amortization of Transition Obligation	—			—			0.1
Effect of Plan Settlement (a)	—			(1.6		)	—
Net Postretirement Health and Life Expense (Credit)	$(1.6)			$(1.5)				$9.6


(a)	Result of the termination of a legacy benefit plan.



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2014		2013
Millions
Net (Gain) Loss	$16.4		$(30.2)
Prior Service Credit Arising During the Period	(3.0	)	—
Amortization of Prior Service Credit	2.5		2.5
Amortization of Loss	(0.5	)	(1.6	)
Amount Recognized due to Plan Settlement (a)	—		(0.2	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$15.4		$(29.5)


(a)	Result of the termination of a legacy benefit plan.

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



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2015		$36.5		$8.0
2016		$37.1		$8.5
2017		$38.2		$8.8
2018		$39.0		$9.0
2019		$39.9		$9.4
Years 2020 – 2024		$207.8		$49.4

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, 2015, are as follows:



	Pension		Postretirement Health and Life
Millions
Net Loss		$17.9		$0.4
Prior Service Cost (Credit)	0.2		(3.0		)
Total Pension and Postretirement Health and Life Cost (Credit)		$18.1	$(2.6)



Assumptions Used to Determine Benefit Obligation
As of December 31	2014	2013
Discount Rate
Pension	4.30%	4.93%
Postretirement Health and Life	4.33%	4.96%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	6.75%	7.25%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2020



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2014	2013	2012
Discount Rate	4.93 - 4.96%	4.10 - 4.13%	4.54 - 4.56%
Expected Long-Term Return on Plan Assets
Pension	8.00%	8.25%	8.25%
Postretirement Health and Life	6.40 - 8.00%	6.60 - 8.25%	6.60 - 8.25%
Rate of Compensation Increase	3.70 - 4.30%	4.30 - 4.60%	4.30 - 4.60%

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. The decrease in the discount rates used as of December 31, 2014 increased the pension and postretirement health and life benefit obligations by approximately $53 million and $14 million, respectively.

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. In 2014, revised mortality tables were released, and the Company adopted updated mortality tables as of December 31, 2014. The adoption of updated mortality tables increased the pension and postretirement health and life benefit obligations as of December 31, 2014 by approximately $25 million and $8 million, respectively.



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		$1.5	$(1.2)
Effect on Postretirement Health and Life Obligation		$21.6	$(17.7)



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2014		2013		2014		2013
Equity Securities	48	%	52	%	58	%	63	%
Debt Securities	39	%	34	%	34	%	29	%
Private Equity	8	%	9	%	8	%	8	%
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 as of December 31, 2014 (no shares as of December 31, 2013).

As of December 31, 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, 2014.



Plan Asset Target Allocations	Pension		Postretirement Health and Life (a)
Equity Securities	56	%	60	%
Debt Securities	35	%	37	%
Real Estate	9	%	3	%
	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, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$56.4	—			$88.5
U.S. Mid-cap Growth (a)	13.6		23.9		—		37.5
U.S. Small-cap (a)	13.9		24.4		—		38.3
International	46.1		45.9		—		92.0
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		201.0		—		203.7
Cash Equivalents	11.9		—		—		11.9
Other Types of Investments:
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$120.4		$351.6		$72.2		$544.2

(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)

Fair Value (Continued)



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2013		$46.8			$26.5
Actual Return on Plan Assets	1.2			2.8
Purchases, sales, and settlements, net	(4.7		)	(0.4		)
Balance as of December 31, 2014		$43.3			$28.9



	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	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

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

Fair Value (Continued)

Postretirement Health and Life Fair Value



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$29.3	—		—			$29.3
U.S. Mid-cap Growth (a)	20.0		—		—		20.0
U.S. Small-cap (a)	12.6		—		—		12.6
International	30.6		—		—		30.6
Debt Securities:
Mutual Funds	44.5		—		—		44.5
Fixed Income	—			$9.9	—		9.9
Cash Equivalents	3.4		—		—		3.4
Other Types of Investments:
Private Equity Funds	—		—			$12.9	12.9
Total Fair Value of Assets		$140.4		$9.9		$12.9		$163.2


(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, 2013		$13.1
Actual Return on Plan Assets	1.4
Purchases, sales, and settlements, net	(1.6		)
Balance as of December 31, 2014		$12.9



	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).

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, 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

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.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References+ Details

Employee Stock and Incentive Plans

12 Months Ended

Dec. 31, 2014

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 $9.1 million in 2014 ($8.4 million in 2013; $7.7 million in 2012).

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.



As of December 31	2014		2013		2012
Millions
ESOP Shares
Allocated	1.9		2.0		2.2
Unallocated	0.3		0.5		0.7
Total	2.2		2.5		2.9
Fair Value of Unallocated Shares		$13.2		$24.1		$28.7

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 0.8 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, 2014.

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	2014		2013		2012
Millions
Performance Shares		$1.6		$1.7		$1.4
Restricted Stock Units	0.7		0.7		0.7
Total Share-Based Compensation Expense		$2.3		$2.4		$2.1
Income Tax Benefit		$1.0		$1.0		$0.9

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized share-based compensation costs during the years ended December 31, 2014, 2013 or 2012.

As of December 31, 2014, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.8 million and $0.7 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.6 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, 2014, 2013 and 2012.



	2014				2013				2012
	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,	108,299			$44.10	395,678			$42.28	460,234			$41.68
Granted (a)	—		—		—		—		—		—
Exercised	(42,020	)		$43.65	(287,379	)		$41.60	(49,075	)		$35.84
Forfeited	—		—		—		—		(15,481	)		$44.86
Outstanding as of December 31,	66,279			$44.39	108,299			$44.10	395,678			$42.28
Exercisable as of December 31,	66,279			$44.39	108,299			$43.17	395,678			$41.71


(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 $1.8 million in 2014. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.4 million during 2014 ($2.2 million in 2013; $0.3 million in 2012).



	Range of Exercise Price
As of December 31, 2014	$39.10 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	21,849		44,430
Weighted Average Remaining Contractual Life (Years)	2.9		1.7
Weighted Average Exercise Price		$39.27		$46.90
Aggregate Intrinsic Value (Millions)		$0.3		$0.4

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2014, 2013 and 2012.



	2014				2013				2012
	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,	114,765			$47.02	107,899			$40.73	128,333			$36.54
Granted (a)	47,992			$46.47	45,830			$52.15	38,764			$44.70
Awarded	(36,515	)		$42.01	(18,605	)		$35.10	(41,009	)		$34.25
Unearned Grant Award	—		—		(18,606	)		$35.10	(17,575	)		$34.25
Forfeited	(6,607	)		$48.29	(1,753	)		$47.26	(614	)		$34.49
Non-vested as of December 31,	119,635			$48.26	114,765			$47.02	107,899			$40.73

(a) Shares granted include accrued dividends.

NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were 43,081 and 38,344 performance shares granted in January 2014 and 2015, for the three-year performance periods ending in 2016 and 2017, 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 $2.0 million and $2.3 million, respectively.

There were 36,515 performance shares awarded in February 2014 for the three-year performance period ending in 2013. There were no performance shares awarded in February 2015 for the three-year performance period ending in 2014. The grant date fair value of the shares awarded was $1.5 million and zero, respectively.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2014, 2013 and 2012.



	2014				2013				2012
	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,	55,982			$40.85	56,415			$36.61	63,464			$32.57
Granted (a)	19,645			$48.44	21,440			$43.41	18,162			$40.83
Awarded	(18,860	)		$37.64	(20,939	)		$32.03	(24,707	)		$29.43
Forfeited	(2,879	)		$45.92	(934	)		$41.02	(504	)		$31.80
Available as of December 31,	53,888			$44.47	55,982			$40.85	56,415			$36.61

(a) Shares granted include accrued dividends.

There were 17,491 and 15,633 restricted stock units granted in January 2014 and 2015, for the vesting periods ending in 2016 and 2017, respectively. The grant date fair value of the restricted stock units granted was $0.9 million and $0.9 million, respectively.

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

There were 17,815 restricted stock units awarded in February 2015. 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, 2014

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
2014
Operating Revenue		$296.5		$260.7		$288.9		$290.7
Operating Income		$48.3		$28.2		$60.8		$51.5
Net Income Attributable to ALLETE		$33.5		$16.8		$41.6		$32.9
Earnings Per Share of Common Stock
Basic		$0.81		$0.40		$0.97		$0.73
Diluted		$0.80		$0.40		$0.97		$0.73
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

- 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, 2014

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
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
2014 Trade Accounts Receivable		$1.1		$1.8	—		$1.8		$1.1
Finance Receivables – Long-Term		$0.6	—		—	—			$0.6
Deferred Asset Valuation Allowance
2012 Deferred Tax Assets		$0.4	$2.0		—	—			$2.4
2013 Deferred Tax Assets		$2.4	$5.6		—	—			$8.0
2014 Deferred Tax Assets		$8.0		$14.1	—	—			$22.1


(a)	Includes uncollectible accounts written off.

Operations and Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Operations and Significant Accounting Policies [Abstract]

Financial Statement Preparation [Policy Text Block]

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]

Business Segments [Policy Text Block]

Revenue Recognition [Policy Text Block]

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Land Inventory [Policy Text Block]

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]

Long-Term Finance Receivables [Policy Text Block]

Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts.

Available-for-Sale Securities [Policy Text Block]

We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities.

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.



Inventories
As of December 31	2014		2013
Millions
Fuel (a)		$29.0		$13.1
Materials and Supplies	51.5		46.2
Total Inventories		$80.5		$59.3

Property, Plant and Equipment [Policy Text Block]

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

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Derivatives [Policy Text Block]

Changes in the fair value of the Swap were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swap 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 Swap will be recorded in earnings when the hedged transactions occurs or when it is probable it will not occur. Gains or losses on the interest rate hedging transaction are reflected as a component of Interest Expense on the Consolidated Statement of Income.

Stock-Based Compensation [Policy Text Block]

Environmental Liabilities [Policy Text Block]

Unamortized Discount and Premium on Debt [Policy Text Block]

Income Taxes [Policy Text Block]

Excise Taxes [Policy Text Block]

Business Combinations Policy [Policy Text Block]

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. In connection with finalizing purchase price accounting, the Company recorded minor adjustments to certain assets and liabilities, which are reflected in the table below. These adjustments had no impact on the results of operations. Fair value measurements were valued primarily using the discounted cash flow method.

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, development or normal operation of the asset.

Regulatory Assets and Liabilities [Policy Text Block]

Our regulated utility operations are subject to the accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. 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 regulatory authority or over the corresponding period related to the asset or liability.

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]

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 these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the tables below.

Fair Value 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]

Employee Stock Ownership Plan (ESOP) [Policy Text Block]

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, 2014

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	2014		2013		2012
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$51.3		$47.5		$42.7
Cash Paid During the Period for Income Taxes		$5.1		$0.5	—
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment		$21.7		$8.3	$20.2
Capitalized Asset Retirement Costs		$22.4	$(0.7)			$17.1
AFUDC – Equity		$7.8		$4.6		$5.1
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan		$19.5	—		—

Accounts Receivable [Table Text Block]



Accounts Receivable
As of December 31	2014		2013
Millions
Trade Accounts Receivable
Billed		$85.5		$78.7
Unbilled	18.6		18.7
Less: Allowance for Doubtful Accounts	1.1		1.1
Total Accounts Receivable		$103.0		$96.3

Inventories [Table Text Block]

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	2014		2013
Millions
Fuel (a)		$29.0		$13.1
Materials and Supplies	51.5		46.2
Total Inventories		$80.5		$59.3


(a)	Fuel inventory was lower at December 31, 2013 primarily due to the timing of coal shipments.

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets
As of December 31	2014		2013
Millions
Deferred Fuel Adjustment Clause		$16.3		$23.0
Construction Costs for Development Project (a)	48.2		—
Restricted Cash (b)	2.7		—
Other	14.8		12.1
Total Prepayments and Other Current Assets		$82.0		$35.1


(a)	Construction Costs for Development Project acquired/incurred due to ALLETE Clean Energy’s acquisition on November 20, 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 7. Acquisitions.)


(b)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements.

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



Other Current Liabilities
As of December 31	2014		2013
Millions
Customer Deposits		$19.7		$26.0
Power Purchase Agreements (a)	19.4		—
Construction Deposits Received for Development Project (b)	54.3		—
Other	27.4		26.6
Total Other Current Liabilities		$120.8		$52.6


(a)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)


(b)	Construction Deposits Received for Development Project are due to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayment and Other Current Assets table and Note 7. Acquisitions.)



Other Non-Current Liabilities
As of December 31	2014		2013
Millions
Asset Retirement Obligation (a)		$109.2		$81.8
Power Purchase Agreements (b)	110.7		—
Other	45.1		45.4
Total Other Non-Current Liabilities		$265.0		$127.2


(a)	The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.


(b)	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)

Business Segments (Tables)

12 Months Ended

Dec. 31, 2014

Business Segments [Abstract]

Business Segments [Table Text Block]



	Consolidated			Regulated Operations			Investments and Other
Millions
Year Ended December 31, 2014
Operating Revenue		$1,136.8			$1,003.5			$133.3
Fuel and Purchased Power Expense	356.1			356.1			—
Operating and Maintenance Expense	456.2			345.6			110.6
Depreciation Expense	135.7			118.0			17.7
Operating Income	188.8			183.8			5.0
Interest Expense	(54.8		)	(46.9		)	(7.9		)
Equity Earnings in ATC	19.6			19.6			—
Other Income	8.6			7.8			0.8
Income (Loss) Before Non-Controlling Interest and Income Taxes	162.2			164.3			(2.1		)
Income Tax Expense (Benefit)	36.7			39.9			(3.2		)
Net Income	125.5			124.4			1.1
Less: Non-Controlling Interest in Subsidiaries	0.7			—			0.7
Net Income Attributable to ALLETE		$124.8			$124.4			$0.4

As of December 31, 2014
Total Assets		$4,360.8			$3,709.6			$651.2
Capital Additions		$604.3			$583.5			$20.8

NOTE 2. BUSINESS SEGMENTS (Continued)



	Consolidated			Regulated Operations			Investments and Other
Millions
Year Ended December 31, 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 Non-Controlling Interest and 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		)
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income (Loss) Attributable to ALLETE		$104.7			$104.9		$(0.2)

As of December 31, 2013
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
Year Ended December 31, 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 Non-Controlling Interest and 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
Less: Non-Controlling Interest in Subsidiaries	—			—			—
Net Income Attributable to ALLETE		$97.1			$96.1		$1.0

As of December 31, 2012
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, 2014

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment [Table Text Block]



Property, Plant and Equipment
As of December 31	2014			2013
Millions
Regulated Utility		$3,903.3			$3,380.0
Construction Work in Progress	355.4			303.9
Accumulated Depreciation	(1,260.2		)	(1,181.7		)
Regulated Utility Plant - Net	2,998.5			2,502.2
Investments and Other Operations (a)	357.8			131.3
Construction Work in Progress	5.9			3.4
Accumulated Depreciation	(75.8		)	(60.4		)
Investments and Other Operations Plant - Net	287.9			74.3
Property, Plant and Equipment - Net		$3,286.4			$2,576.5


(a)	Includes primarily ALLETE Clean Energy, BNI Coal and a small amount of non-rate base generation.

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



Estimated Useful Lives of Property, Plant and Equipment
Generation	5 to 50 years	Distribution	18 to 65 years
Transmission	44 to 67 years	Investments and Other Operations	5 to 44 years

Asset Retirement Obligation [Table Text Block]



Asset Retirement Obligation
Millions
Obligation as of December 31, 2012		$77.9
Accretion	4.6
Revisions in estimated cash flows	(0.7		)
Obligation as of December 31, 2013	81.8
Accretion	5.5
Liabilities recognized (a)	23.0
Liabilities settled	(0.5		)
Revisions in estimated cash flows	(0.6		)
Obligation as of December 31, 2014		$109.2


(a)	The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.

Jointly-Owned Facilities and Projects (Tables)

12 Months Ended

Dec. 31, 2014

Jointly-Owned Facilities and Projects [Abstract]

Jointly-Owned Facilities and Projects [Table Text Block]

Our investments in jointly-owned facilities and projects and the related ownership percentages are as follows:



Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Regulated Utility Plant As of December 31	Plant in Service		Accumulated Depreciation		Construction Work in Progress		% Ownership
Millions
2014
Boswell Unit 4		$419.1		$209.1		$168.1	80
CapX2020 Projects	55.5		1.7		44.0		9.3 - 14.7
Total		$474.6		$210.8		$212.1
2013
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, 2014

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities
As of December 31	2014		2013
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$16.3		$23.0
Total Current Regulatory Assets	16.3		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	223.9		164.1
Cost Recovery Riders (c)	59.7		39.6
Income Taxes	46.6		35.3
Asset Retirement Obligations	17.8		16.0
PPACA Income Tax Deferral	5.0		5.0
Other	4.3		3.8
Total Non-Current Regulatory Assets	357.3		263.8
Total Regulatory Assets		$373.6		$286.8

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$42.9		$19.7
Plant Removal Obligations	22.8		19.7
Income Taxes	13.4		17.0
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	3.5		16.3
Other	11.6		8.3
Total Non-Current Regulatory Liabilities		$94.2		$81.0


(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 the Consolidated Balance Sheet. (See Note 17. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are due to capital expenditures related to our Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC (Tables)

12 Months Ended

Dec. 31, 2014

Investment in ATC [Abstract]

ALLETE's Interest in ATC [Table Text Block]



ALLETE’s Investment in ATC
Year Ended December 31	2014			2013
Millions
Equity Investment Beginning Balance		$114.6			$107.3
Cash Investments	3.9			3.1
Equity in ATC Earnings	19.6			20.3
Distributed ATC Earnings	(17.0		)	(16.1		)
Equity Investment Ending Balance		$121.1			$114.6

ATC Summarized Financial Data [Table Text Block]



ATC Summarized Financial Data
Balance Sheet Data
As of December 31	2014		2013
Millions
Current Assets		$66.4		$80.7
Non-Current Assets	3,728.7		3,509.5
Total Assets		$3,795.1		$3,590.2
Current Liabilities		$313.1		$381.4
Long-Term Debt	1,701.0		1,550.0
Other Non-Current Liabilities	163.8		126.2
Members’ Equity	1,617.2		1,532.6
Total Liabilities and Members’ Equity		$3,795.1		$3,590.2



Income Statement Data
Year Ended December 31	2014		2013		2012
Millions
Revenue		$635.0		$626.3		$603.2
Operating Expense	307.4		295.1		281.0
Other Expense	88.9		83.6		84.8
Net Income		$238.7		$247.6		$237.4
ALLETE’s Equity in Net Income		$19.6		$20.3		$19.4

Acquisitions Acquisitions (Tables)

12 Months Ended

Dec. 31, 2014

Acquisitions [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	14.3
Property, Plant and Equipment – Net	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
Other Current Liabilities (b)		$15.2
Long-Term Debt Due Within One Year	2.2
Long-Term Debt	21.1
Power Purchase Agreements	99.4
Other Non-Current Liabilities	10.6
Non-Controlling Interest (c)	7.1
Total Liabilities and Non-Controlling Interest Assumed	$155.6
Net Identifiable Assets Acquired		$26.9


(a)	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.


(c)	The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.



Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment – Net	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Other Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
Other Non-Current Liabilities	17.0
Total Liabilities Assumed	$48.7
Net Identifiable Assets Acquired		$15.1


(a)	Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


(b)	Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.

Investments (Tables)

12 Months Ended

Dec. 31, 2014

Investments [Abstract]

Other Investments and ALLETE Properties [Table Text Block]



Other Investments
As of December 31	2014		2013
Millions
ALLETE Properties		$88.2		$89.9
Available-for-sale Securities (a)	18.9		17.7
Cash Equivalents (b)	2.9		34.2
Other	4.4		4.5
Total Other Investments		$114.4		$146.3


(a)	As of December 31, 2014, 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 $1.7 million, in three years to less than five years was $2.6 million, and in five or more years was $5.9 million.


(b)	During 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.



ALLETE Properties
As of December 31	2014			2013
Millions
Land Inventory Beginning Balance		$85.4			$86.5
Cost of Sales	(2.2		)	(1.5		)
Other	0.6			0.4
Land Inventory Ending Balance	83.8			85.4
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)	1.2			1.4
Other	3.2			3.1
Total Real Estate Assets		$88.2			$89.9

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
2012	$27.4	$0.5	$1.1	$26.8
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—
2012		$1.5	—	—

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
As of December 31	Cost	Gain	Loss	Fair Value
2014	$19.6	$0.2	$0.9	$18.9
2013	$18.3	—	$0.6	$17.7
2012	$27.4	$0.5	$1.1	$26.8
		Net	Gross Realized
Year Ended December 31		Proceeds	Gain	Loss
2014		$3.6	$0.2	—
2013		$16.1	$2.2	—
2012		$1.5	—	—

Fair Value (Tables)

12 Months Ended

Dec. 31, 2014

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 (a)
Available-for-sale – Equity Securities		$7.9	—		—		$7.9
Available-for-sale – 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 (b)	—			$16.8	—		$16.8
Derivatives – Interest Rate Swap (c)	—		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


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.


(c)	Included in Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3	Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$8.1	—		—		$8.1
Available-for-sale – Corporate Debt Securities	—			$10.8	—	10.8
Cash Equivalents	2.9		—		—	2.9
Total Fair Value of Assets		$11.0		$10.8	—		$21.8

Liabilities:
Deferred Compensation (b)	—			$16.2	—		$16.2
Derivatives – Interest Rate Swap (c)	—		0.3		—	0.3
Total Fair Value of Liabilities	—			$16.5	—		$16.5
Total Net Fair Value of Assets (Liabilities)		$11.0	$(5.7)		—		$5.3


(a)	Included in Other Investments on the Consolidated Balance Sheet.


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.


(c)	Included in Current Liabilities - Other on the Consolidated Balance Sheet.

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
December 31, 2014	$1,373.5	$1,484.5
December 31, 2013	$1,110.2	$1,131.7

- 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, 2014

Short-Term and Long-Term Debt [Abstract]

Long-term Debt [Table Text Block]

During 2014, we issued $375.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:



Issue Date	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%
September 16, 2014	September 15, 2021	$60 Million	3.02%
September 16, 2014	September 15, 2029	$50 Million	3.74%
September 16, 2014	September 15, 2044	$50 Million	4.39%



Long-Term Debt
As of December 31	2014		2013
Millions
First Mortgage Bonds
6.94% Series Due 2014	—		$18.0
7.70% Series Due 2016	$20.0		20.0
1.83% Series Due 2018	50.0		50.0
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
3.02% Series Due 2021	60.0		—
3.40% Series Due 2022	75.0		—
4.95% Pollution Control Series F Due 2022	—		111.0
6.02% Series Due 2023	75.0		75.0
3.69% Series Due 2024	60.0		—
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		40.0
3.74% Series Due 2029	50.0		—
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		60.0
4.95% Series Due 2044	40.0		—
5.05% Series Due 2044	40.0		—
4.39% Series Due 2044	50.0		—
Unsecured Term Loan Variable Rate Due 2015	75.0		75.0
Senior Unsecured Notes 5.99% Due 2017	50.0		50.0
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020	24.6		24.6
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025	27.8		27.8
SWL&P First Mortgage Bonds 4.15% Series Due 2028	15.0		15.0
Other Long-Term Debt, 0.08% – 7.50% Due 2015 – 2037	59.1		41.8
Total Long-Term Debt	1,373.5		1,110.2
Less: Due Within One Year	100.7		27.2
Net Long-Term Debt		$1,272.8		$1,083.0

- 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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-Section 50

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Reference 6: 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)

-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 02

-Paragraph 22

-Article 5

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

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-Name Accounting Standards Codification

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-Paragraph 8

-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 942

-SubTopic 470

-Section 50

-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, 2014

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, 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
Employee Stock Purchase Program	18	0.8
Invest Direct	378	18.9
Options and Stock Awards	78	8.0
Equity Issuance Program	1,851	90.0
Forward Sale Agreement and Issuance	1,807	85.2
Contributions to Pension	396	19.5
Balance as of December 31, 2014	45,929		$1,107.6

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
2014
Net Income Attributable to ALLETE		$124.8			$124.8
Average Common Shares	42.9		0.2	43.1
Earnings Per Share		$2.91			$2.90
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

Income Tax Expense (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



Income Tax Expense
Year Ended December 31	2014			2013			2012
Millions
Current Tax Expense
Federal (a)	$1.1			—			—
State (a)	2.9			$0.1			$0.5
Total Current Tax Expense	4.0			0.1			0.5
Deferred Tax Expense
Federal	25.3			22.9			37.0
State	8.2			6.5			1.4
Investment Tax Credit Amortization	(0.8		)	(0.8		)	(0.9		)
Total Deferred Tax Expense	32.7			28.6			37.5
Total Income Tax Expense		$36.7			$28.7			$38.0

(a)

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	2014			2013			2012
Millions
Income Before Non-Controlling Interest and Income Taxes		$162.2			$133.4			$135.1
Statutory Federal Income Tax Rate	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$56.8			$46.7			$47.3
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	7.2			4.3			1.2
Regulatory Differences for Utility Plant	(3.5		)	(2.2		)	(2.2		)
Production Tax Credits	(23.7		)	(19.2		)	(7.6		)
Other	(0.1		)	(0.9		)	(0.7		)
Total Income Tax Expense		$36.7			$28.7			$38.0

Deferred Tax Assets and Liabilities [Table Text Block]



Deferred Tax Assets and Liabilities
As of December 31	2014			2013
Millions
Deferred Tax Assets
Employee Benefits and Compensation		$102.2			$66.3
Property Related	102.7			82.2
NOL Carryforwards	156.5			112.8
Tax Credit Carryforwards	95.7			55.1
Power Purchase Agreements	51.8			—
Other	17.0			16.9
Gross Deferred Tax Assets	525.9			333.3
Deferred Tax Asset Valuation Allowance	(22.1		)	(8.0		)
Total Deferred Tax Assets		$503.8			$325.3
Deferred Tax Liabilities
Property Related		$848.8			$656.2
Regulatory Asset for Benefit Obligations	89.9			58.7
Unamortized Investment Tax Credits	10.3			11.1
Partnership Basis Differences	41.9			36.7
Other	16.1			22.7
Total Deferred Tax Liabilities		$1,007.0			$785.4
Net Deferred Income Taxes		$503.2			$460.1
Recorded as:
Net Current Deferred Tax Assets		$7.5		$19.0
Net Long-Term Deferred Tax Liabilities	510.7			479.1
Net Deferred Income Taxes		$503.2			$460.1



NOL and Tax Credit Carryforwards
As of December 31	2014	2013
Millions
Federal NOL Carryforwards (a)	$413.7		$279.8
Federal Tax Credit Carryforwards	$59.3	$35.5
State NOL Carryforwards (a)	$184.7	$156.3
State Tax Credit Carryforwards (b)	$14.7	$11.9

NOL and Tax Credit Carryforwards [Table Text Block]



NOL and Tax Credit Carryforwards
As of December 31	2014	2013
Millions
Federal NOL Carryforwards (a)	$413.7		$279.8
Federal Tax Credit Carryforwards	$59.3	$35.5
State NOL Carryforwards (a)	$184.7	$156.3
State Tax Credit Carryforwards (b)	$14.7	$11.9


(a)	Pretax amounts.


(b)	Net of a $21.7 million valuation allowance as of December 31, 2014 ($7.7 million as of December 31, 2013).

Gross Unrecognized Income Tax Benefits [Table Text Block]



Gross Unrecognized Income Tax Benefits	2014			2013			2012
Millions
Balance at January 1		$1.2			$2.7			$11.4
Additions for Tax Positions Related to the Current Year	—			0.1			—
Additions for Tax Positions Related to Prior Years	1.0			1.3			—
Reductions for Tax Positions Related to Prior Years	—			—			(8.7		)
Reductions for Settlements	—			(2.9		)	—
Lapse of Statute	(0.2		)	—			—
Balance as of December 31		$2.0			$1.2			$2.7

- 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, 2014

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 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)

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2014, 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, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)		$(0.3)	$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.3	)	(5.2	)	0.2	(5.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	0.1		1.2		—	1.3
Net Other Comprehensive Income (Loss)	(0.2	)	(4.0	)	0.2	(4.0	)
Ending Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)		$(0.1)	$(21.1)

Reclassifications from Accumulated Other Comprehensive Loss [Table Text Block]

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2014, were as follows:



	Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	December 31,
	2014
Millions
Unrealized Gains on Available-for-sale Securities (a)	$(0.2)
Income Taxes (b)	0.1
Total, Net of Income Taxes	$(0.1)

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.3
Actuarial Gains and Losses (c)	(2.3	)
Total	(2.0	)
Income Taxes (b)	0.8
Total, Net of Income Taxes	$(1.2)
Total Reclassifications	$(1.3)


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


(b)	Included in Income Tax Expense on our 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.)

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 our Consolidated Statement of Income.


(b)	Included in Income Tax Expense on our 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, 2014

Defined Benefit Plan Disclosure [Line Items]

Estimated Future Benefit Payments [Table Text Block]



Estimated Future Benefit Payments	Pension		Postretirement Health and Life
Millions
2015		$36.5		$8.0
2016		$37.1		$8.5
2017		$38.2		$8.8
2018		$39.0		$9.0
2019		$39.9		$9.4
Years 2020 – 2024		$207.8		$49.4

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		$17.9		$0.4
Prior Service Cost (Credit)	0.2		(3.0		)
Total Pension and Postretirement Health and Life Cost (Credit)		$18.1	$(2.6)

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



Assumptions Used to Determine Benefit Obligation
As of December 31	2014	2013
Discount Rate
Pension	4.30%	4.93%
Postretirement Health and Life	4.33%	4.96%
Rate of Compensation Increase	3.70 - 4.30%	3.70 - 4.30%
Health Care Trend Rates
Trend Rate	6.75%	7.25%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2020



Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31	2014	2013	2012
Discount Rate	4.93 - 4.96%	4.10 - 4.13%	4.54 - 4.56%
Expected Long-Term Return on Plan Assets
Pension	8.00%	8.25%	8.25%
Postretirement Health and Life	6.40 - 8.00%	6.60 - 8.25%	6.60 - 8.25%
Rate of Compensation Increase	3.70 - 4.30%	4.30 - 4.60%	4.30 - 4.60%

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



Actual Plan Asset Allocations	Pension				Postretirement Health and Life (a)
	2014		2013		2014		2013
Equity Securities	48	%	52	%	58	%	63	%
Debt Securities	39	%	34	%	34	%	29	%
Private Equity	8	%	9	%	8	%	8	%
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	56	%	60	%
Debt Securities	35	%	37	%
Real Estate	9	%	3	%
	100	%	100	%


(a)	Includes VEBAs and irrevocable grantor trusts.

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Obligation and Funded Status [Table Text Block]



Pension Obligation and Funded Status
At December 31	2014			2013
Millions
Accumulated Benefit Obligation		$661.4			$577.6
Change in Benefit Obligation
Obligation, Beginning of Year		$622.8			$652.1
Service Cost	8.3			9.9
Interest Cost	29.8			26.0
Actuarial (Gain) Loss	72.6			(49.2		)
Benefits Paid	(36.9		)	(33.5		)
Participant Contributions	17.9			17.5
Obligation, End of Year		$714.5			$622.8
Change in Plan Assets
Fair Value, Beginning of Year		$501.6			$460.1
Actual Return on Plan Assets	41.0			56.5
Employer Contribution (a)	38.5			18.5
Benefits Paid	(36.9		)	(33.5		)
Fair Value, End of Year		$544.2			$501.6
Funded Status, End of Year	$(170.3)			$(121.2)

Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
Current Liabilities	$(1.2)			$(1.1)
Non-Current Liabilities	$(169.1)			$(120.1)


(a)	Includes participant contributions noted above.

Unrecognized Costs [Table Text Block]



Unrecognized Pension Costs
As of December 31	2014		2013
Millions
Net Loss		$250.4		$194.9
Prior Service Cost	0.2		0.4
Total Unrecognized Pension Costs		$250.6		$195.3

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Pension Expense
Year Ended December 31	2014			2013			2012
Millions
Service Cost		$8.3			$9.9			$9.1
Interest Cost	29.8			26.0			26.4
Expected Return on Plan Assets	(38.2		)	(35.2		)	(35.4		)
Amortization of Loss	14.2			21.5			17.5
Amortization of Prior Service Cost	0.3			0.3			0.3
Net Pension Expense		$14.4			$22.5			$17.9

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



Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2014		2013
Millions
Net (Gain) Loss	$69.8		$(70.4)
Amortization of Prior Service Cost	(0.3	)	(0.3	)
Amortization of Loss	(14.2	)	(21.5	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$55.3		$(92.2)

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
As of December 31	2014		2013
Millions
Projected Benefit Obligation		$714.5		$622.8
Accumulated Benefit Obligation		$661.4		$577.6
Fair Value of Plan Assets		$544.2		$501.6

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$32.1		$56.4	—			$88.5
U.S. Mid-cap Growth (a)	13.6		23.9		—		37.5
U.S. Small-cap (a)	13.9		24.4		—		38.3
International	46.1		45.9		—		92.0
Debt Securities:
Mutual Funds	0.1		—		—		0.1
Fixed Income	2.7		201.0		—		203.7
Cash Equivalents	11.9		—		—		11.9
Other Types of Investments:
Private Equity Funds	—		—			$43.3	43.3
Real Estate	—		—		28.9		28.9
Total Fair Value of Assets		$120.4		$351.6		$72.2		$544.2

(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, 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



Recurring Fair Value Measures
Activity in Level 3	Private Equity Funds			Real Estate
Millions
Balance as of December 31, 2013		$46.8			$26.5
Actual Return on Plan Assets	1.2			2.8
Purchases, sales, and settlements, net	(4.7		)	(0.4		)
Balance as of December 31, 2014		$43.3			$28.9

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
At December 31	2014			2013
Millions
Change in Benefit Obligation
Obligation, Beginning of Year		$151.9			$168.8
Service Cost	3.4			3.9
Interest Cost	7.3			6.8
Actuarial (Gain) Loss	18.1			(18.8		)
Benefits Paid	(8.9		)	(9.9		)
Participant Contributions	2.6			2.7
Plan Amendments	(2.9		)	—
Plan Curtailments	(0.6		)	—
Settlements (a)	—			(1.6		)
Obligation, End of Year		$170.9			$151.9
Change in Plan Assets
Fair Value, Beginning of Year		$157.0			$131.0
Actual Return on Plan Assets	11.6			21.4
Employer Contribution	1.1			11.7
Participant Contributions	2.6			2.7
Benefits Paid	(9.1		)	(9.8		)
Fair Value, End of Year		$163.2			$157.0
Funded Status, End of Year	$(7.7)			$5.1

Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
Non-Current Assets	$6.6			$19.4
Current Liabilities	$(0.9)			$(0.9)
Non-Current Liabilities	$(13.4)			$(13.4)


(a)	Result of the termination of a legacy benefit plan.

Unrecognized Costs [Table Text Block]



Unrecognized Postretirement Health and Life Costs
As of December 31	2014		2013
Millions
Net (Gain) Loss	$6.9		$(9.0)
Prior Service Credit	(10.6	)	(10.1	)
Total Unrecognized Postretirement Health and Life Credit	$(3.7)		$(19.1)

Components of Net Periodic Expense [Table Text Block]



Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31	2014			2013			2012
Millions
Service Cost		$3.4			$3.9			$4.2
Interest Cost	7.3			6.8			9.4
Expected Return on Plan Assets	(10.3		)	(9.7		)	(9.9		)
Amortization of Loss	0.5			1.6			7.5
Amortization of Prior Service Credit	(2.5		)	(2.5		)	(1.7		)
Amortization of Transition Obligation	—			—			0.1
Effect of Plan Settlement (a)	—			(1.6		)	—
Net Postretirement Health and Life Expense (Credit)	$(1.6)			$(1.5)				$9.6


(a)	Result of the termination of a legacy benefit plan.

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



Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31	2014		2013
Millions
Net (Gain) Loss	$16.4		$(30.2)
Prior Service Credit Arising During the Period	(3.0	)	—
Amortization of Prior Service Credit	2.5		2.5
Amortization of Loss	(0.5	)	(1.6	)
Amount Recognized due to Plan Settlement (a)	—		(0.2	)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities	$15.4		$(29.5)


(a)	Result of the termination of 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		$1.5	$(1.2)
Effect on Postretirement Health and Life Obligation		$21.6	$(17.7)

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, 2014
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Equity Securities:
U.S. Large-cap (a)		$29.3	—		—			$29.3
U.S. Mid-cap Growth (a)	20.0		—		—		20.0
U.S. Small-cap (a)	12.6		—		—		12.6
International	30.6		—		—		30.6
Debt Securities:
Mutual Funds	44.5		—		—		44.5
Fixed Income	—			$9.9	—		9.9
Cash Equivalents	3.4		—		—		3.4
Other Types of Investments:
Private Equity Funds	—		—			$12.9	12.9
Total Fair Value of Assets		$140.4		$9.9		$12.9		$163.2


(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, 2013		$13.1
Actual Return on Plan Assets	1.4
Purchases, sales, and settlements, net	(1.6		)
Balance as of December 31, 2014		$12.9



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, 2014

Employee Stock and Incentive Plans [Abstract]

Employee Stock Ownership Plan [Table Text Block]



As of December 31	2014		2013		2012
Millions
ESOP Shares
Allocated	1.9		2.0		2.2
Unallocated	0.3		0.5		0.7
Total	2.2		2.5		2.9
Fair Value of Unallocated Shares		$13.2		$24.1		$28.7

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	2014		2013		2012
Millions
Performance Shares		$1.6		$1.7		$1.4
Restricted Stock Units	0.7		0.7		0.7
Total Share-Based Compensation Expense		$2.3		$2.4		$2.1
Income Tax Benefit		$1.0		$1.0		$0.9

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, 2014, 2013 and 2012.



	2014				2013				2012
	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,	108,299			$44.10	395,678			$42.28	460,234			$41.68
Granted (a)	—		—		—		—		—		—
Exercised	(42,020	)		$43.65	(287,379	)		$41.60	(49,075	)		$35.84
Forfeited	—		—		—		—		(15,481	)		$44.86
Outstanding as of December 31,	66,279			$44.39	108,299			$44.10	395,678			$42.28
Exercisable as of December 31,	66,279			$44.39	108,299			$43.17	395,678			$41.71


(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, 2014	$39.10 to $41.35		$44.15 to $48.65
Options Outstanding and Exercisable:
Number Outstanding and Exercisable	21,849		44,430
Weighted Average Remaining Contractual Life (Years)	2.9		1.7
Weighted Average Exercise Price		$39.27		$46.90
Aggregate Intrinsic Value (Millions)		$0.3		$0.4

Performance Shares [Table Text Block]

Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2014, 2013 and 2012.



	2014				2013				2012
	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,	114,765			$47.02	107,899			$40.73	128,333			$36.54
Granted (a)	47,992			$46.47	45,830			$52.15	38,764			$44.70
Awarded	(36,515	)		$42.01	(18,605	)		$35.10	(41,009	)		$34.25
Unearned Grant Award	—		—		(18,606	)		$35.10	(17,575	)		$34.25
Forfeited	(6,607	)		$48.29	(1,753	)		$47.26	(614	)		$34.49
Non-vested as of December 31,	119,635			$48.26	114,765			$47.02	107,899			$40.73

(a) Shares granted include 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, 2014, 2013 and 2012.



	2014				2013				2012
	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,	55,982			$40.85	56,415			$36.61	63,464			$32.57
Granted (a)	19,645			$48.44	21,440			$43.41	18,162			$40.83
Awarded	(18,860	)		$37.64	(20,939	)		$32.03	(24,707	)		$29.43
Forfeited	(2,879	)		$45.92	(934	)		$41.02	(504	)		$31.80
Available as of December 31,	53,888			$44.47	55,982			$40.85	56,415			$36.61

(a) Shares granted include accrued dividends.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

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
2014
Operating Revenue		$296.5		$260.7		$288.9		$290.7
Operating Income		$48.3		$28.2		$60.8		$51.5
Net Income Attributable to ALLETE		$33.5		$16.8		$41.6		$32.9
Earnings Per Share of Common Stock
Basic		$0.81		$0.40		$0.97		$0.73
Diluted		$0.80		$0.40		$0.97		$0.73
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

Operations and Significant Accounting Policies (Details) (USD $)

12 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Square Butte PPA [Member]

Dec. 31, 2014

Square Butte Coal-fired Unit [Member]

Square Butte PPA [Member]

Dec. 31, 2014

Municipal Customers [Member]

Customers

Dec. 31, 2014

Retail Customers [Member]

Customers

Dec. 31, 2014

Electric [Member]

Customers

Dec. 31, 2014

Natural Gas [Member]

Customers

Dec. 31, 2014

Water [Member]

Customers

Feb. 10, 2015

Subsequent Event [Member]

Feb. 10, 2015

Subsequent Event [Member]

Customers

Dec. 31, 2014

Investments and Other [Member]

acre

Subsequent Events [Line Items]

Business Acquisition, Effective Date of Acquisition

Feb. 10, 2015

Business Acquisition, Name of Acquired Entity

U.S. Water Services

Payments to Acquire Businesses, Gross

$ 168,000,000

Business Acquisition, Acquired Business Number of Customers

3,600

Acquired Business, Customer Retention

90.00%

Business Combination, Reason for Business Combination

The acquisition of U.S. Water Services is consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.

Customer Information [Line Items]

Number of Customers

144,000

15,000

12,000

10,000

Investments and Other [Abstract]

Land in Minnesota (in acres)

5,000

Real Estate Sales Revenue Recognition, Minimum Contract Price Cash Collections Requirement (Percent)

20.00%

Amortization of Power Purchase Agreements

12,700,000

Long-term Contract for Purchase of Electric Power [Line Items]

Output Purchased (Percent)

50.00%

Output Purchased (MW)

227.5

Trade Accounts Receivable [Abstract]

Billed

85,500,000

78,700,000

Unbilled

18,600,000

18,700,000

Less: Allowance for Doubtful Accounts

1,100,000

Total Accounts Receivable - Net

103,000,000

96,300,000

Inventories [Abstract]

Fuel

29,000,000

^[1]

13,100,000

^[1]

Materials and Supplies

51,500,000

46,200,000

Total Inventories

80,500,000

59,300,000

Impairement of Long-Lived Assets [Abstract]

Land Impairment

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

16,300,000

23,000,000

Construction Costs for Development Project

48,200,000

^[2]

Restricted Cash

2,700,000

^[3]

Other

14,800,000

12,100,000

Total Prepayments and Other Current Assets

82,000,000

35,100,000

Other Non-Current Assets [Abstract]

Restricted Cash

5,300,000

5,400,000

Other Current Liabilities [Abstract]

Customer Deposits

19,700,000

26,000,000

Power Purchase Agreements

19,400,000

^[4]

Construction Deposits Received for Development Project

54,300,000

^[5]

Other

27,400,000

26,600,000

Total Other Current Liabilities

120,800,000

52,600,000

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

109,200,000

^[6]

81,800,000

^[6]

77,900,000

Power Purchase Agreements

110,700,000

^[4]

Other

45,100,000

45,400,000

Total Other Non-Current Liabilities

$ 265,000,000

$ 127,200,000

Income Taxes [Abstract]

More Likely Than Not Definition

50.00%

[1]	Fuel inventory was lower at December 31, 2013 primarily due to the timing of coal shipments.
[2]	Construction Costs for Development Project acquired/incurred due to ALLETE Clean Energy’s acquisition on November 20, 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 7. Acquisitions.)
[3]	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements.
[4]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)
[5]	Construction Deposits Received for Development Project are due to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayment and Other Current Assets table and Note 7. Acquisitions.)
[6]	The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized	$ 51.3	$ 47.5	$ 42.7
Cash Paid During the Period for Income Taxes	5.1	0.5	0
Noncash Investing and Financing Activities [Abstract]
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment	21.7	8.3	20.2
Capitalized Asset Retirement Costs	22.4	(0.7)	17.1
AFUDC - Equity	7.8	4.6	5.1
ALLETE Common Stock Contributed to the Defined Benefit Pension Plan	$ 19.5	$ 0	$ 0

Operations and Significant Accounting Policies - Concentraion of Credit Risk (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Customer Information [Line Items]
Major Customer, Percent of Consolidated Revenue	10.80%	12.00%	12.30%
Large Power Customer [Member]
Customer Information [Line Items]
Number of Customers	10
Large Power Customers, Accounts Receivable	$ 14.7	$ 14.2

Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Segments [Line Items]
Operating Revenue									$ 1,136.8	$ 1,018.4	$ 961.2
Fuel and Purchased Power Expense									356.1	334.8	308.7
Operating and Maintenance Expense									456.2	412.9	397.1
Depreciation Expense									135.7	116.6	100.2
Operating Income (Loss)	51.5	60.8	28.2	48.3	46.9	38.4	24.4	44.4	188.8	154.1	155.2
Interest Expense									(54.8)	(50.3)	(45.5)
Equity Earnings in ATC									19.6	20.3	19.4
Other Income									8.6	9.3	6.0
Income (Loss) Before Non-Controlling Interest and Income Taxes									162.2	133.4	135.1
Income Tax Expense (Benefit)									36.7	28.7	38.0
Net Income (Loss)									125.5	104.7	97.1
Less: Non-Controlling Interest in Subsidiaries									0.7	0	0
Net Income (Loss) Attributable to ALLETE	32.9	41.6	16.8	33.5	33.0	25.2	14.0	32.5	124.8	104.7	97.1
Total Assets	4,360.8				3,476.8				4,360.8	3,476.8	3,253.4
Capital Additions									604.3	339.5	432.2
Regulated Operations [Member]
Business Segments [Line Items]
Operating Revenue									1,003.5	925.5	874.4
Fuel and Purchased Power Expense									356.1	334.8	308.7
Operating and Maintenance Expense									345.6	322.4	310.0
Depreciation Expense									118.0	110.2	93.9
Operating Income (Loss)									183.8	158.1	161.8
Interest Expense									(46.9)	(42.1)	(39.8)
Equity Earnings in ATC									19.6	20.3	19.4
Other Income									7.8	4.7	5.1
Income (Loss) Before Non-Controlling Interest and Income Taxes									164.3	141.0	146.5
Income Tax Expense (Benefit)									39.9	36.1	50.4
Net Income (Loss)									124.4	104.9	96.1
Less: Non-Controlling Interest in Subsidiaries									0	0	0
Net Income (Loss) Attributable to ALLETE									124.4	104.9	96.1
Total Assets	3,709.6				3,160.8				3,709.6	3,160.8	2,962.4
Capital Additions									583.5	326.3	418.2
Investments and Other [Member]
Business Segments [Line Items]
Land in Minnesota (in acres)	5,000								5,000
Operating Revenue									133.3	92.9	86.8
Fuel and Purchased Power Expense									0	0	0
Operating and Maintenance Expense									110.6	90.5	87.1
Depreciation Expense									17.7	6.4	6.3
Operating Income (Loss)									5.0	(4.0)	(6.6)
Interest Expense									(7.9)	(8.2)	(5.7)
Equity Earnings in ATC									0	0	0
Other Income									0.8	4.6	0.9
Income (Loss) Before Non-Controlling Interest and Income Taxes									(2.1)	(7.6)	(11.4)
Income Tax Expense (Benefit)									(3.2)	(7.4)	(12.4)
Net Income (Loss)									1.1	(0.2)	1.0
Less: Non-Controlling Interest in Subsidiaries									0.7	0	0
Net Income (Loss) Attributable to ALLETE									0.4	(0.2)	1.0
Total Assets	651.2				316.0				651.2	316.0	291.0
Capital Additions									$ 20.8	$ 13.2	$ 14.0

Property, Plant and Equipment (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Property, Plant and Equipment [Line Items]

Total Property, Plant and Equipment - Net

$ 3,286.4

$ 2,576.5

Asset Retirement Obligation [Roll Forward]

Beginning Obligation

81.8

^[1]

77.9

Accretion

5.5

4.6

Liabilities recognized

23.0

^[1]

Liabilities settled

(0.5)

Revisions in estimated cash flows

(0.6)

(0.7)

Ending Obligation

109.2

^[1]

81.8

^[1]

Regulated Utility [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment

3,903.3

3,380.0

Construction Work in Progress

355.4

303.9

Accumulated Depreciation

(1,260.2)

(1,181.7)

Property, Plant and Equipment - Net

2,998.5

2,502.2

Regulated Utility [Member] | Generation [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

5 years

Regulated Utility [Member] | Generation [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

50 years

Regulated Utility [Member] | Transmission [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

44 years

Regulated Utility [Member] | Transmission [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

67 years

Regulated Utility [Member] | Distribution [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

18 years

Regulated Utility [Member] | Distribution [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

65 years

Investments and Other Operations [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment

357.8

^[2]

131.3

^[2]

Construction Work in Progress

5.9

3.4

Accumulated Depreciation

(75.8)

(60.4)

Property, Plant and Equipment - Net

$ 287.9

$ 74.3

Investments and Other Operations [Member] | Investments and Other Operations [Member] | Minimum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

5 years

Investments and Other Operations [Member] | Investments and Other Operations [Member] | Maximum [Member]

Property, Plant and Equipment [Line Items]

Estimated Useful Lives

44 years

[1]	The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.
[2]	Includes primarily ALLETE Clean Energy, BNI Coal and a small amount of non-rate base generation.

Jointly-Owned Facilities and Projects (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	$ 474.6	$ 438.9
Accumulated Depreciation	210.8	198.5
Construction Work in Progress	212.1	129.2
CapX2020 [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	3
Project in Progress [Member] \| CapX2020 [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	1
Completed Project [Member] [Member] \| CapX2020 [Member]
Jointly-Owned Facilities and Projects [Line Items]
Number of Projects	2
Boswell Unit 4 [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	80.00%	80.00%
Generating Capacity (MW)	585.0
% Not Owned	20.00%
Plant in Service	419.1	416.1
Accumulated Depreciation	209.1	197.5
Construction Work in Progress	168.1	71.5
CapX2020 Projects [Member]
Jointly-Owned Facilities and Projects [Line Items]
Plant in Service	55.5	22.8
Accumulated Depreciation	1.7	1.0
Construction Work in Progress	$ 44.0	$ 57.7
CapX2020 Projects [Member] \| Minimum [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	9.30%	9.30%
CapX2020 Projects [Member] \| Maximum [Member]
Jointly-Owned Facilities and Projects [Line Items]
% Ownership	14.70%	14.70%

Regulatory Matters - Utility Rates (Details) (USD $) In Millions, unless otherwise specified					0 Months Ended		0 Months Ended
	Dec. 31, 2014 Hydro Project [Member]	Dec. 31, 2014 Bison Wind Energy Center [Member] MW	Dec. 31, 2014 Bison 4 Wind Project [Member] MW	Dec. 31, 2014 Municipal Customers [Member] Customers	Jun. 01, 2011 MPUC 2010 MN Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Dec. 31, 2014 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Years Customers	Jan. 01, 2013 PSCW 2012 Wisconsin Rate Case [Member] Retail Customers [Member]
Public Utilities, General Disclosures [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		16
Length of Notice Required to Terminate (Years)						3
Generating Capacity (MW)		497.0	205.0
Estimated Capital Expenditures	$ 90
Capital Cost Spent to Date			$ 333

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

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Asset

$ 16.3

$ 23.0

Non-Current Regulatory Asset

357.3

263.8

Total Regulatory Assets

373.6

286.8

Non-Current Regulatory Liability

94.2

81.0

Types of Net Regulatory Assets Earning Returns

No regulatory assets or liabilities are currently earning a return.

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

42.9

19.7

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

22.8

19.7

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

13.4

17.0

Defined Benefit Pension and Other Postretirement Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

3.5

^[1]

16.3

^[1]

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liability

11.6

8.3

Deferred Fuel Adjustment Clause [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Asset

16.3

^[2]

23.0

^[2]

Defined Benefit Pension and Other Postretirement Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

223.9

^[1]

164.1

^[1]

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

46.6

35.3

Asset Retirement Obligation [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

17.8

16.0

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

59.7

^[3]

39.6

^[3]

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

5.0

Other [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Asset

$ 4.3

$ 3.8

[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 the 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 assets are due to capital expenditures related to our Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.

Investment in ATC (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 29, 2015 Subsequent Event [Member]
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 2015	$ 1.9
Subsequent Event [Line Items]
Cash Investments	3.9	3.1		0.4
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Beginning Balance	114.6	107.3
Cash Investments	3.9	3.1		0.4
Equity Earnings in ATC	19.6	20.3	19.4
Distributed ATC Earnings	(17.0)	(16.1)
Equity Investment Ending Balance	121.1	114.6	107.3
Balance Sheet Data [Abstract]
Current Assets	66.4	80.7
Non-Current Assets	3,728.7	3,509.5
Total Assets	3,795.1	3,590.2
Current Liabilities	313.1	381.4
Long-Term Debt	1,701.0	1,550.0
Other Non-Current Liabilities	163.8	126.2
Members' Equity	1,617.2	1,532.6
Total Liabilities and Members' Equity	3,795.1	3,590.2
Income Statement Data [Abstract]
Revenue	635.0	626.3	603.2
Operating Expense	307.4	295.1	281.0
Other Expense	88.9	83.6	84.8
Net Income	238.7	247.6	237.4
ALLETE's Equity in Net Income	$ 19.6	$ 20.3	$ 19.4

Investment in ATC - FERC Complaint (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Loss Contingencies [Line Items]
Equity Method Investment, Proposed Return on Common Equity	9.15%
Equity Method Investment, Approved Return on Common Equity	12.20%
Equity Method Investment, Ownership Percentage	8.00%
Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Basis Point Reduction on Approved Rate of Return on Common Equity	50
Effect on Future Earnings, Amount	$ 0.5
ATC [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	18
Rainy River Energy [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 1

Acquisitions - ACE Wind Acquisition (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

Feb. 11, 2014

Dec. 31, 2014

Jan. 30, 2014

Dec. 31, 2013

Dec. 31, 2014

Armenia Mountain [Member]

Jan. 30, 2014

Armenia Mountain [Member]

Jan. 30, 2014

ACE Wind [Member]

Mar. 31, 2014

ACE Wind [Member]

Dec. 31, 2014

ACE Wind [Member]

Dec. 31, 2013

ACE Wind [Member]

Dec. 31, 2014

Storm Lake II [Member]

Dec. 31, 2014

Lake Benton [Member]

Dec. 31, 2014

Condon [Member]

Business Acquisition [Line Items]

Business Combination, Reason for Business Combination

Business Acquisition, Effective Date of Acquisition

Jan. 30, 2014

Business Acquisition, Name of Acquired Entity

Armenia Mountain

Storm Lake II

Lake Benton

Condon

Business Acquisition, Transaction Costs

$ 26.9

Generating Capacity (MW)

101.0

104.0

Assets [Abstract]

Cash and Cash Equivalents

3.8

Other Current Assets

14.3

Property, Plant and Equipment - Net

156.9

Other Non-Current Assets

7.5

^[1]

Total Assets Acquired

182.5

Liabilities [Abstract]

Other Current Liabilities

15.2

^[2]

Long-Term Debt Due Within one Year

2.2

Long-Term Debt

21.1

Power Purchase Agreements

110.7

^[3]

99.4

Other Non-Current Liabilities

10.6

Non-Controlling Interest

7.1

^[4]

Total Liabilities and Non-Controlling Interest Assumed

155.6

Net Identifiable Assets Acquired

26.9

Purchase option

0.3

Goodwill

2.9

Power Purchase Agreements - Current

19.4

^[3]

12.4

Business Combination, Acquisition Related Costs

1.4

Business Acquisition, Pro Forma Information, Description

not material

not materia

Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests

$ 6.0

[1]	Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[2]	Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.
[3]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)
[4]	The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.

Acquisitions - Wind Development Project (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

3 Months Ended

12 Months Ended

Nov. 20, 2014

Dec. 31, 2014

Dec. 31, 2013

Nov. 20, 2014

Assets [Abstract]

Construction in Progress, Gross

$ 48.2

^[1]

$ 48.2

^[1]

$ 0

^[1]

Liabilities [Abstract]

Deposits

54.3

^[2]

54.3

^[2]

Wind Development Project [Member]

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Nov. 20, 2014

Payments to Acquire Businesses, Gross

27.0

Generating Capacity (MW)

107.0

Contractual Sales Price

200

Assets [Abstract]

Cash and Cash Equivalents

3.6

Construction in Progress, Gross

48.2

23.4

Goodwill

Liabilities [Abstract]

Total Liabilities and Non-Controlling Interest Assumed

Business Combination, Acquisition Related Cost

not material

Business Acquisition, Pro Forma Information, Description

not material

Deposits

$ 54.3

[1]	Construction Costs for Development Project acquired/incurred due to ALLETE Clean Energy’s acquisition on November 20, 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 7. Acquisitions.)
[2]	Construction Deposits Received for Development Project are due to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayment and Other Current Assets table and Note 7. Acquisitions.)

Acquisitions - Storm Lake I (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 17, 2014

Storm Lake I [Member]

Dec. 31, 2014

Storm Lake I [Member]

Dec. 31, 2014

Storm Lake I [Member]

Dec. 17, 2014

Storm Lake I [Member]

Business Acquisition [Line Items]

Business Acquisition, Effective Date of Acquisition

Dec. 17, 2014

Business Acquisition, Name of Acquired Entity

Storm Lake I

Payments to Acquire Businesses, Gross

$ 15.0

Generating Capacity (MW)

108.0

Assets [Abstract]

Cash and Cash Equivalents

0.4

Other Current Assets

4.7

Property, Plant and Equipment - Net

47.3

Other Non-Current Assets

11.4

^[1]

Total Assets Acquired

63.8

Liabilities [Abstract]

Other Current Liabilities

8.2

^[2]

Power Purchase Agreements

110.7

^[3]

23.5

Other Non-Current Liabilities

17.0

Total Liabilities and Non-Controlling Interest Assumed

48.7

Net Identifiable Assets Acquired

15.1

Restricted Cash and Investments, Noncurrent

0.4

Goodwill Description

immaterial

Power Purchase Agreements - Current

$ 19.4

^[3]

$ 0

^[3]

$ 7.5

Business Combination, Acquisition Related Cost

not material

Business Acquisition, Pro Forma Information, Description

not material

[1]	Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[2]	Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.
[3]	Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)

Investments (Details) (USD $)

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Investments [Abstract]

ALLETE Properties

$ 88,200,000

$ 89,900,000

Available-for-sale Securities

18,900,000

^[1]

17,700,000

^[1]

26,800,000

Cash Equivalents

2,900,000

^[2]

34,200,000

^[2]

Other

4,400,000

4,500,000

Total Other Investments

114,400,000

146,300,000

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

600,000

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

1,700,000

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

2,600,000

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

5,900,000

ALLETE Properties [Roll Forward]

Land Inventory Beginning Balance

83,800,000

85,400,000

86,500,000

Cost of Sales

(2,200,000)

(1,500,000)

Other

600,000

400,000

Land Inventory Ending Balance

83,800,000

85,400,000

86,500,000

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

1,200,000

1,400,000

Other

3,200,000

3,100,000

Total Real Estate Assets

88,200,000

89,900,000

Land Impairment

Long-Term Finance Receivables, Allowance

$ 600,000

[1]	As of December 31, 2014, 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 $1.7 million, in three years to less than five years was $2.6 million, and in five or more years was $5.9 million.
[2]	During 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.

Investments - Available-for-sale Securities (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Available-for-sale Securities [Abstract]

Cost

$ 19.6

$ 18.3

$ 27.4

Gross Unrealized Gain

0.2

0.5

Gross Unrealized Loss

0.9

0.6

1.1

Fair Value

18.9

^[1]

17.7

^[1]

26.8

Net Proceeds

3.6

16.1

1.5

Gross Realized Gain

0.2

2.2

Gross Realized Loss

$ 0

[1]	As of December 31, 2014, 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 $1.7 million, in three years to less than five years was $2.6 million, and in five or more years was $5.9 million.

- Definition

Investments in debt and equity securities which are categorized neither as held-to-maturity nor trading and which are intended to be sold or mature more than one year from the balance sheet date or operating cycle, if longer. Such securities are reported at fair value; unrealized gains (losses) related to Available-for-sale Securities are excluded from earnings and reported in a separate component of shareholders' equity (other comprehensive income), unless the Available-for-sale security is designated as a hedge or is determined to have had an other than temporary decline in fair value below its amortized cost basis. All or a portion of the unrealized holding gain (loss) of an Available-for-sale security that is designated as being hedged in a fair value hedge is recognized in earnings during the period of the hedge, as are other than temporary declines in fair value below the cost basis for investments in equity securities and debt securities that an entity intends to sell or it is more likely than not that it will be required to sell before the recovery of its amortized cost basis. Other than temporary declines in fair value below the cost basis for debt securities categorized as Available-for-sale that an entity does not intend to sell and for which it is not more likely than not that the entity will be required to sell before the recovery of its amortized cost basis are bifurcated into credit losses and losses related to all other factors. Other than temporary declines in fair value below cost basis related to credit losses are recognized in earnings, and losses related to all other factors are recognized in other comprehensive income.

+ References+ Details

Derivatives (Details) (Interest Rate Swap [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Interest Rate Swap Variable Rate Basis	one-month LIBOR
Interest Rate Swap Fixed Interest Rate	0.75%
Interest Rate Cash Flow Hedge Effectiveness Assessment and Measurement	Cash flows from the Swap are expected to be highly effective. If it is determined that the Swap ceases 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 assessment of hedge effectiveness resulted in no ineffectiveness recorded for the year ended December 31, 2014.
Interest Rate Swap Liability	$ 0.3	$ 0.6
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Interest Rate Swap Liability		0.3
Other Current Liabilities [Member]
Derivative [Line Items]
Interest Rate Swap Liability		$ 0.3

Fair Value - Recurring Fair Value Measures (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Investments [Abstract]

Cash Equivalents

$ 2.9

^[1]

$ 34.2

^[1]

Recurring Fair Value Measures [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

8.1

^[2]

7.9

^[2]

Available-for-sale - Corporate Debt Securities

10.8

^[2]

9.8

^[2]

Cash Equivalents

2.9

^[2]

34.2

^[2]

Total Fair Value of Assets

21.8

51.9

Liabilities [Abstract]

Deferred Compensation

16.2

^[3]

16.8

^[3]

Derivatives - Interest Rate Swap

0.3

^[4]

0.6

^[5]

Total Fair Value of Liabilities

16.5

17.4

Total Net Fair Value of Assets (Liabilities)

5.3

34.5

Fair Value Hierarchy Transfers, All Levels

Recurring Fair Value Measures [Member] | Level 1 [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

8.1

^[2]

7.9

^[2]

Available-for-sale - Corporate Debt Securities

^[2]

Cash Equivalents

2.9

^[2]

34.2

^[2]

Total Fair Value of Assets

11.0

42.1

Liabilities [Abstract]

Deferred Compensation

^[3]

Derivatives - Interest Rate Swap

^[4]

^[5]

Total Fair Value of Liabilities

Total Net Fair Value of Assets (Liabilities)

11.0

42.1

Recurring Fair Value Measures [Member] | Level 2 [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

^[2]

Available-for-sale - Corporate Debt Securities

10.8

^[2]

9.8

^[2]

Cash Equivalents

^[2]

Total Fair Value of Assets

10.8

9.8

Liabilities [Abstract]

Deferred Compensation

16.2

^[3]

16.8

^[3]

Derivatives - Interest Rate Swap

0.3

^[4]

0.6

^[5]

Total Fair Value of Liabilities

16.5

17.4

Total Net Fair Value of Assets (Liabilities)

(5.7)

(7.6)

Recurring Fair Value Measures [Member] | Level 3 [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

^[2]

Available-for-sale - Corporate Debt Securities

^[2]

Cash Equivalents

^[2]

Total Fair Value of Assets

Liabilities [Abstract]

Deferred Compensation

^[3]

Derivatives - Interest Rate Swap

^[4]

^[5]

Total Fair Value of Liabilities

Total Net Fair Value of Assets (Liabilities)

Fair Value Activity in Level 3

$ 0

[1]	During 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[4]	Included in Current Liabilities - Other on the Consolidated Balance Sheet.
[5]	Included in Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.

Fair Value - Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,373.5	$ 1,110.2
Long-Term Debt, Including Current Portion - Fair Value	$ 1,484.5	$ 1,131.7

- 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	9 Months Ended						0 Months Ended				0 Months Ended		0 Months Ended		0 Months Ended		0 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Jan. 30, 2014	Dec. 31, 2013	Dec. 31, 2014 Lines of Credit [Member]	Dec. 31, 2013 Lines of Credit [Member]	Mar. 04, 2014 ALLETE Bonds 3.69% Due March2024 [Member]	Mar. 04, 2014 ALLETE Bonds 4.95% Due March2044 [Member]	Jun. 26, 2014 ALLETE Bonds 3.40% Due July2022 [Member]	Jun. 26, 2014 ALLETE Bonds 3.40% Due July2022 [Member]	Jun. 26, 2014 ALLETE Bonds 5.05% Due July2044 [Member]	Jun. 26, 2014 ALLETE Bonds 5.05% Due July2044 [Member]	Sep. 16, 2014 ALLETE Bonds 3.02% Due September 2021 [Member]	Sep. 16, 2014 ALLETE Bonds 3.02% Due September 2021 [Member]	Sep. 16, 2014 ALLETE Bonds 3.74% Due September 2029 [Member]	Sep. 16, 2014 ALLETE Bonds 3.74% Due September 2029 [Member]	Sep. 16, 2014 ALLETE Bonds 4.39% Due September 2044 [Member]	Sep. 16, 2014 ALLETE Bonds 4.39% Due September 2044 [Member]
Debt Instrument [Line Items]
Short-Term Debt		$ 104.4		$ 27.2
Line of Credit Facility, Maximum Borrowing Capacity					408.4	406.4
Lines of Credit, Current		47.5		5.4
Letters of Credit Drawn		3.7		0
Long-Term Debt		1,272.8		1,083.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Long-term Debt			23.3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt			2.2
Long-Term Debt Due Within One Year		100.7		27.2
Long-Term Debt, 2016 Maturities		24.9
Long-Term Debt, 2017 Maturities		54.6
Long-Term Debt, 2018 Maturities		54.8
Long-Term Debt, 2019 Maturities		46.9
Long-Term Debt, Thereafter Maturities		1,091.6
Proceeds from Issuance of First Mortgage Bond	$ 375.0						$ 60.0	$ 40.0	$ 75.0		$ 40.0		$ 60.0		$ 50.0		$ 50.0
First Mortgage Bonds, Interest Rate							3.69%	4.95%		3.40%		5.05%		3.02%		3.74%		4.39%

Short-term and Long-term Debt - Schedule of Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total Long-term Debt	$ 1,373.5	$ 1,110.2
Less: Due Within One Year	100.7	27.2
Net Long-Term Debt	1,272.8	1,083.0
6.94% Series Due 2014 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	0	18.0
7.70% Series Due 2016 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	20.0	20.0
1.83% Series Due 2018 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	50.0	50.0
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
3.02% Series Due 2021 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	60.0	0
3.40% Series Due 2022 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	75.0	0
4.95% Pollution Control Series F Due 2022 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	0	111.0
6.02% Series Due 2023 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	75.0	75.0
3.69% Series Due 2024 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	60.0	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	40.0
3.74% Series Due 2029 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	50.0	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	60.0
4.95% Series Due 2044 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	40.0	0
5.05% Series Due 2044 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	40.0	0
4.39% Series Due 2044 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	50.0	0
Unsecured Term Loan Variable Rate Due 2015 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	75.0	75.0
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 Due 2015-2020 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	24.6	24.6
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
SWL&P First Mortgage Bonds 4.15% Series Due 2028 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	15.0	15.0
Other Long-Term Debt, 0.08%-7.50% Due 2015-2037 [Member]
Debt Instrument [Line Items]
Total Long-term Debt	$ 59.1	$ 41.8

- Definition

+ References+ Details

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Square Butte PPA [Member]	Dec. 31, 2013 Square Butte PPA [Member]	Dec. 31, 2012 Square Butte PPA [Member]	Dec. 31, 2014 Square Butte PPA [Member] Square Butte Coal-fired Unit [Member] MW	Dec. 31, 2014 Minnkota PPA [Member] MW	Dec. 31, 2014 Oliver Wind I PPA [Member] MW	Dec. 31, 2014 Oliver Wind II PPA [Member] MW	Dec. 31, 2014 Manitoba Hydro PPA (expires May 2020) [Member] MW	Dec. 31, 2014 Manitoba Hydro PPA (expires April 2022) [Member] MWh	Dec. 31, 2014 Manitoba Hydro PPA (expires 2035) [Member] MW Years	Sep. 30, 2014 Manitoba Hydro PPA (expires 2040) [Member] MW Years	Dec. 31, 2014 Great River Energy PPA (expires 2020) [Member] MW	Mar. 31, 2015 Great River Energy Capacity Only PPA (expires 2020) [Member] Subsequent Event [Member] MW
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)				455.0
Output Entitlement				50.00%
PPA Counterparty Debt Outstanding	$ 402.9
Annual Debt Service	45
Power Purchased under Long-term Contracts	70.1	71.1	67.1
Interest Expense	10.5	10.5	11.1
Output Being Purchased (MW)					50	50	48	50		250	133	50	50
Term of Contract (Years)										15	20
Fixed Capacity Charges						$ 0	$ 0
Output Being Purchased (MWh)									1,000,000

Commitments, Guarantees and Contingencies - North Dakota Wind Development (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014 kV Miles
DC Transmission Line from Square Butte [Member]
North Dakota Wind Development [Line Items]
Transmission Line Length (Miles)	465
Transmission Line Capacity (kV)	250
Bison Wind Energy Center [Member]
North Dakota Wind Development [Line Items]
Generating Unit Capacity (MW)	497.0
Bison 4 Wind Project [Member]
North Dakota Wind Development [Line Items]
Generating Unit Capacity (MW)	205.0
Capital Cost Spent to Date	$ 333

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leasing Agreements [Line Items]
Operating Leases, Future Minimum Payments, Current	$ 13.4
Operating Leases, Future Minimum Payments, Due in Two Years	11.4
Operating Leases, Future Minimum Payments, Due in Three Years	10.6
Operating Leases, Future Minimum Payments, Due in Four Years	9.5
Operating Leases, Future Minimum Payments, Due in Five Years	8.3
Operating Leases, Future Minimum Payments, Due Thereafter	27.3
Operating Leases, Rent Expense	14.8	13.8	11.5
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, 2014
CapX2020 [Member]
Transmission [Line Items]
Number of Projects	3
Estimated Capital Expenditures	$ 105
Capital Cost Spent to Date	99
Great Northern Transmission Line [Member]
Transmission [Line Items]
Transmission Line Length (Miles)	220
Transmission Line Capacity (kV)	500
Great Northern Transmission Line [Member] \| Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	560
Great Northern Transmission Line [Member] \| Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	$ 710
Project in Progress [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of Projects	1
Completed Project [Member] [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of Projects	2

Commitments, Guarantees and Contingencies - Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2014 MW
Clean Water Act - Aquatic Organisms [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs		$ 15
Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs		130
Boswell Unit 4 [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures		250
Capital Cost Spent to Date		145
NOV Consent Decree Obligation [Member]
Environmental Matters [Line Items]
Generating Capacity (MW)		200.0
Environmental Remediation Expense		4.2
Civil Penalty	1.4
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Generating Capacity (MW)		500.0
Estimated Capital Expenditures		600
NOV Consent Decree [Member] \| Minimum [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures		20
NOV Consent Decree [Member] \| Maximum [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures		$ 40

Commitments, Guarantees and Contingencies - Other Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Years	Dec. 31, 2013
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Surety Bond	$ 49.5
Letters of Credit	0.6
Estimated Reclamation Liability	49.3
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	72.00%	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
	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]
Common Stock Outstanding, Shares		45,900,000	41,400,000
Contributions to Pension, Value		$ 19.5	$ 0	$ 0
Common Stock [Member]
Class of Stock [Line Items]
Common Stock Outstanding, Shares		45,929,000	41,401,000	39,377,000	37,513,000
Common Stock Outstanding, Value		1,107.6	885.2	784.7	705.6
Employee Stock Purchase Program, Shares		18,000	16,000	20,000
Employee Stock Purchase Program, Value		0.8	0.7	0.8
Invest Direct, Shares		378,000	395,000	474,000
Invest Direct, Value		18.9	18.5	19.2
Options and Stock Awards, Shares		78,000	301,000	95,000
Options and Stock Awards, Value		8.0	17.9	6.0
Equity Issuance Program, Shares		1,851,000	1,312,000	1,275,000
Equity Issuance Program, Value		90.0	63.4	53.1
Forward Sale Agreement and Issuance, Shares		1,807,000
Forward Sales Agreement and Issuance, Value		85.2
Contributions to Pension, Shares	400,000	396,000	0	0
Contributions to Pension, Value	$ 19.5	$ 19.5
Equity Issuance Program Shares Authorized		9,600,000
Equity Issuance Program Shares Available for Issuance		1,300,000
Antidilutive Options to Purchase Shares of Common Stock Excluded from the Computation of Earnings Per Share			0	200,000

Common Stock and Earnings Per Share - Forward Contracts (Details) (Forward Contracts [Member], USD $) In Millions, except Per Share data, unless otherwise specified	0 Months Ended			12 Months Ended		0 Months Ended
	Sep. 05, 2014	Mar. 04, 2014	Feb. 26, 2014	Dec. 31, 2014	Feb. 04, 2014	Feb. 04, 2015 Subsequent Event [Member]	Feb. 04, 2015 Subsequent Event [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Indexed Shares			2.8
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share			$ 48.01
Common Stock, Shares, Issued	1.4				0.4		1.4
Proceeds from Issuance or Sale of Equity	$ 65.0	$ 20.2				$ 65.4
Forward Contract Indexed to Issuer's Equity, Dilutive effect				0

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 32.9	$ 41.6	$ 16.8	$ 33.5	$ 33.0	$ 25.2	$ 14.0	$ 32.5	$ 124.8	$ 104.7	$ 97.1
Average Common Shares									42.9	39.7	37.6
Earnings Per Share	$ 0.73	$ 0.97	$ 0.40	$ 0.81	$ 0.82	$ 0.63	$ 0.36	$ 0.83	$ 2.91	$ 2.64	$ 2.59
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE									$ 124.8	$ 104.7	$ 97.1
Average Common Shares									43.1	39.8	37.6
Earnings Per Share	$ 0.73	$ 0.97	$ 0.40	$ 0.80	$ 0.82	$ 0.63	$ 0.35	$ 0.83	$ 2.90	$ 2.63	$ 2.58
Dilutive Securities (Shares)									0.2	0.1	0

- 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+ Details

Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income (Expense) [Abstract]
AFUDC - Equity	$ 7.8	$ 4.6	$ 5.1
Gain on Sale of Available-for-sale Securities	0.2	2.2	0
Investment and Other Income	0.6	2.5	0.9
Total Other Income	$ 8.6	$ 9.3	$ 6.0

Income Tax Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	$ 1.1	$ 0	$ 0
State	2.9	0.1	0.5
Total Current Tax Expense	4.0	0.1	0.5
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	25.3	22.9	37.0
State	8.2	6.5	1.4
Investment Tax Credit Amortization	(0.8)	(0.8)	(0.9)
Total Deferred Tax Expense	32.7	28.6	37.5
Total Income Tax Expense	$ 36.7	$ 28.7	$ 38.0

Income Tax Expense - Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Expense [Abstract]
Income Before Non-Controlling Interest and Income Taxes	$ 162.2	$ 133.4	$ 135.1
Statutory Federal Income Tax Rate	35.00%	35.00%	35.00%
Income Taxes Computed at 35 Percent Statutory Federal Rate	56.8	46.7	47.3
Increase (Decrease) in Tax [Abstract]
State Income Taxes - Net of Federal Income Tax Benefit	7.2	4.3	1.2
Regulatory Differences for Utility Plant	(3.5)	(2.2)	(2.2)
Production Tax Credits	(23.7)	(19.2)	(7.6)
Other	(0.1)	(0.9)	(0.7)
Income Tax Expense	$ 36.7	$ 28.7	$ 38.0
Effective Income Tax Rate	22.60%	21.50%	28.10%

Income Tax Expense - Deferred Tax Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred Tax Assets [Abstract]
Employee Benefits and Compensation	$ 102.2	$ 66.3
Property Related	102.7	82.2
NOL Carryforwards	156.5	112.8
Tax Credit Carryforwards	95.7	55.1
Power Purchase Agreements	51.8	0
Other	17.0	16.9
Gross Deferred Tax Assets	525.9	333.3
Deferred Tax Asset Valuation Allowance	(22.1)	(8.0)
Total Deferred Tax Assets	503.8	325.3
Deferred Tax Liabilities [Abstract]
Property Related	848.8	656.2
Regulatory Asset for Benefit Obligations	89.9	58.7
Unamortized Investment Tax Credits	10.3	11.1
Partnership Basis Differences	41.9	36.7
Other	16.1	22.7
Total Deferred Tax Liabilities	1,007.0	785.4
Net Deferred Income Taxes	503.2	460.1
Net Current Deferred Tax Assets	7.5	19.0
Net Long-Term Deferred Tax Liabilities	$ 510.7	$ 479.1

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

Dec. 31, 2014

Dec. 31, 2013

Federal [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforward

$ 413,700,000

^[1]

$ 279,800,000

^[1]

Tax Credit Carryforwards

59,300,000

35,500,000

NOL and Federal Tax Credit Carryforwards, Valuation Allowance

State [Member]

NOL and Tax Credit Carryforwards [Line Items]

NOL Carryforward

184,700,000

^[1]

156,300,000

^[1]

Tax Credit Carryforwards

14,700,000

^[2]

11,900,000

^[2]

State Tax Credit Carryforwards, Valuation Allowance

$ 21,700,000

$ 7,700,000

[1]	Pretax amounts
[2]	Net of a $21.7 million valuation allowance as of December 31, 2014 ($7.7 million as of December 31, 2013).

Income Tax Expense - Gross Unrecognized Income Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Gross Unrecognized Income Tax Benefits [Roll Forward]
Balance at January 1	$ 1.2	$ 2.7	$ 11.4
Additions for Tax Positions Related to the Current Year	0	0.1	0
Additions for Tax Positions Related to Prior Years	1.0	1.3	0
Reduction for Tax Positions Related to Prior Years	0	0	(8.7)
Reductions for Settlements	0	(2.9)	0
Lapse of Statute	(0.2)	0	0
Balance as of December 31	2.0	1.2	2.7
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	0.4
Unrecognized Tax Benefits, Accrued Interest	0	0.5	0.5
Unrecognized Tax Benefits, Interest Expense (Reduction)	0.5	0	0.6
Unrecognized Tax Benefits, Penalties	0	0	0
Reasonably Possible Change in Unrecognized Tax Benefits in Next 12 Months	$ 0.1

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

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Beginning Accumulated Other Comprehensive Loss

$ (17.1)

$ (22.0)

Other Comprehensive Income (Loss) Before Reclassifications

(5.3)

4.6

Amounts Reclassified from Accumulated Other Comprehensive Loss

1.3

0.3

Net Other Comprehensive Income (Loss)

(4.0)

4.9

6.9

Ending Accumulated Other Comprehensive Loss

(21.1)

(17.1)

(22.0)

Other Income (Expense) - Other [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(0.2)

^[1]

2.2

^[1]

Income Tax Expense [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

0.1

^[2]

(0.9)

^[2]

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

0.8

^[2]

1.1

^[2]

Operating Expenses - Operating and Maintenance [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(2.0)

(2.7)

AOCI Reclassification, Amortization of Defined Benefit Pension and Other Postretirement items, Prior Service Costs, Before Tax

0.3

^[3]

0.8

^[3]

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

(2.3)

^[3]

(3.5)

^[3]

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

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Beginning Accumulated Other Comprehensive Loss

(0.1)

Other Comprehensive Income (Loss) Before Reclassifications

(0.3)

1.3

Amounts Reclassified from Accumulated Other Comprehensive Loss

0.1

(1.3)

Net Other Comprehensive Income (Loss)

(0.2)

Ending Accumulated Other Comprehensive Loss

(0.3)

(0.1)

Defined Benefit Pension, Other Postretirement Items [Member]

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Beginning Accumulated Other Comprehensive Loss

(16.7)

(21.5)

Other Comprehensive Income (Loss) Before Reclassifications

(5.2)

3.2

Amounts Reclassified from Accumulated Other Comprehensive Loss

1.2

1.6

Net Other Comprehensive Income (Loss)

(4.0)

4.8

Ending Accumulated Other Comprehensive Loss

(20.7)

(16.7)

Gains and Losses on Cash Flow Hedge [Member]

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

Beginning Accumulated Other Comprehensive Loss

(0.3)

(0.4)

Other Comprehensive Income (Loss) Before Reclassifications

0.2

0.1

Amounts Reclassified from Accumulated Other Comprehensive Loss

Net Other Comprehensive Income (Loss)

0.2

0.1

Ending Accumulated Other Comprehensive Loss

$ (0.1)

$ (0.3)

[1]	Included in Other Income (Expense) – Other on our Consolidated Statement of Income.
[2]	Included in Income Tax Expense on our Consolidated Statement of Income.
[3]	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 - Contributions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Stock Contributions	$ 19.5	$ 0	$ 0
Defined Contribution Plan, Employer Contributions	9.1	8.4	7.7
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Stock Contributions	19.5
Defined Benefit Plans, Employer Cash Contributions	0	0	7.3
Defined Benefit Plans, Estimated Employer Contributions	0
VEBA [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Cash Contributions	0	10.8	1.5
Defined Benefit Plans, Estimated Employer Contributions	0
Irrevocable Grantor Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Employer Cash Contributions	$ 0	$ 2.0	$ 0

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

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Change in Plan Assets [Roll Forward]

Non-Current Liabilities

$ (190.9)

$ (133.4)

Other Investments, Irrevocable Grantor Trusts

114.4

146.3

Pension [Member]

Defined Benefit Plan Disclosure [Line Items]

Accumulated Benefit Obligation

661.4

577.6

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

622.8

652.1

Service Cost

8.3

9.9

9.1

Interest Cost

29.8

26.0

26.4

Actuarial (Gain) Loss

72.6

(49.2)

Benefits Paid

(36.9)

(33.5)

Participant Contributions

17.9

17.5

Obligation, End of Year

714.5

622.8

652.1

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

501.6

460.1

Actual Return on Plan Assets

41.0

56.5

Employer Contribution

38.5

^[1]

18.5

^[1]

Benefits Paid

(36.9)

(33.5)

Fair Value, End of Year

544.2

501.6

460.1

Funded Status, End of Year

(170.3)

(121.2)

Current Liabilities

(1.2)

(1.1)

Non-Current Liabilities

(169.1)

(120.1)

Postretirement Health and Life [Member]

Change in Benefit Obligation [Roll Forward]

Obligation, Beginning of Year

151.9

168.8

Service Cost

3.4

3.9

4.2

Interest Cost

7.3

6.8

9.4

Actuarial (Gain) Loss

18.1

(18.8)

Benefits Paid

(8.9)

(9.9)

Participant Contributions

2.6

2.7

Plan Amendments

(2.9)

Plan Curtailments

(0.6)

Settlements

(1.6)

^[2]

Obligation, End of Year

170.9

151.9

168.8

Change in Plan Assets [Roll Forward]

Fair Value, Beginning of Year

157.0

131.0

Actual Return on Plan Assets

11.6

21.4

Employer Contribution

1.1

11.7

Participant Contributions

2.6

2.7

Benefits Paid

(9.1)

(9.8)

Fair Value, End of Year

163.2

157.0

131.0

Funded Status, End of Year

(7.7)

5.1

Non-Current Assets

6.6

19.4

Current Liabilities

(0.9)

Non-Current Liabilities

(13.4)

Irrevocable Grantor Trust [Member]

Change in Plan Assets [Roll Forward]

Other Investments, Irrevocable Grantor Trusts

$ 17.9

$ 17.8

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

Pension and Other Postretirement Benefit Plans - Unrecognized Costs (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	$ 250.4	$ 194.9
Prior Service Cost (Credit)	0.2	0.4
Total Unrecognized Costs (Credit)	250.6	195.3
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net (Gain) Loss	6.9	(9.0)
Prior Service Cost (Credit)	(10.6)	(10.1)
Total Unrecognized Costs (Credit)	$ (3.7)	$ (19.1)

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

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Pension [Member]

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

Service Cost

$ 8.3

$ 9.9

$ 9.1

Interest Cost

29.8

26.0

26.4

Expected Return on Plan Assets

(38.2)

(35.2)

(35.4)

Amortization of Loss

14.2

21.5

17.5

Amortization of Prior Service Cost (Credit)

0.3

Net Expense (Credit)

14.4

22.5

17.9

Postretirement Health and Life [Member]

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

Service Cost

3.4

3.9

4.2

Interest Cost

7.3

6.8

9.4

Expected Return on Plan Assets

(10.3)

(9.7)

(9.9)

Amortization of Loss

0.5

1.6

7.5

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)

$ (1.6)

$ (1.5)

$ 9.6

[1]	Result of the termination of 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 or Liabilities (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Pension [Member]

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

Net (Gain) Loss

$ 69.8

$ (70.4)

Amortization of Prior Service (Cost) Credit

(0.3)

Amortization of Loss

(14.2)

(21.5)

Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities

55.3

(92.2)

Postretirement Health and Life [Member]

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

Net (Gain) Loss

16.4

(30.2)

Prior Service Credit Arising During the Period

(3.0)

Amortization of Prior Service (Cost) Credit

2.5

Amortization of Loss

(0.5)

(1.6)

Amount Recognized due to Plan Settlement

(0.2)

^[1]

Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities

$ 15.4

$ (29.5)

[1]	Result of the termination of a legacy benefit plan.

- Definition

Amount before tax of cost (credit) of benefit changes attributable to plan participants' prior service resulting from a plan amendment or plan initiation that has not been recognized in net periodic benefit cost (credit).

+ References+ Details

- Definition

Amount before tax of reclassification adjustment from accumulated other comprehensive (income) loss for prior service cost (credit) related to pension and other postretirement benefit plans.

+ References+ Details

- 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

- Definition

Amount before tax of (increase) decrease in the value of the projected benefit obligation related to a change in an actuarial assumption and increase (decrease) in the value of the plan assets resulting from experience different from that assumed, that has not been recognized in net periodic benefit (cost) credit.

+ References+ Details

- Definition

Amount before tax of reclassification adjustment from accumulated other comprehensive income (loss) for actuarial gain (loss) related to pension and other postretirement 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, 2014	Dec. 31, 2013
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected Benefit Obligation	$ 714.5	$ 622.8
Accumulated Benefit Obligation	661.4	577.6
Fair Value of Plan Assets	$ 544.2	$ 501.6

Pension and Other Postretirement Benefit Plans - Estimated Future Benefit Payments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	$ 36.5
2016	37.1
2017	38.2
2018	39.0
2019	39.9
Years 2020 - 2024	207.8
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	8.0
2016	8.5
2017	8.8
2018	9.0
2019	9.4
Years 2020 - 2024	$ 49.4

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, 2014
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	$ 17.9
Prior Service Cost (Credit)	0.2
Total Pension and Postretirement Health and Life Cost (Credit)	18.1
Postretirement Health and Life [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net Loss	0.4
Prior Service Cost (Credit)	(3.0)
Total Pension and Postretirement Health and Life Cost (Credit)	$ (2.6)

Pension and Other Postretirement Benefit Plans - Assumptions Used to Determine Benefit Obligation and Net Periodic Benefit Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.30%	4.93%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Discount Rate	4.93%	4.10%	4.54%
Expected Long-Term Return on Plan Assets	8.00%	8.25%	8.25%
Change in Obligation, Discount Rate	$ 53
Change in Obligation, Mortality Assumption	25
Pension [Member] \| Minimum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Rate of Compensation Increase	3.70%	3.70%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	3.70%	4.30%	4.30%
Pension [Member] \| Maximum [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Rate of Compensation Increase	4.30%	4.30%
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Rate of Compensation Increase	4.30%	4.60%	4.60%
Postretirement Health and Life [Member]
Assumptions Used to Determine Benefit Obligation [Abstract]
Discount Rate	4.33%	4.96%
Trend Rate	6.75%	7.25%
Ultimate Trend Rate	5.00%	5.00%
Year Ultimate Trend Rate Effective	2022	2020
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Discount Rate	4.96%	4.13%	4.56%
Change in Obligation, Discount Rate	14
Change in Obligation, Mortality Assumption	$ 8
Postretirement Health and Life [Member] \| Minimum [Member]
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	6.40%	6.60%	6.60%
Postretirement Health and Life [Member] \| Maximum [Member]
Assumptions Used to Determine Net Periodic Benefit Costs [Abstract]
Expected Long-Term Return on Plan Assets	8.00%	8.25%	8.25%

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, 2014
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	$ 1.5
Effect of One Percent Increase on Postretirement Health and Life Obligation	21.6
Effect of One Percent Decrease on Total of Postretirement Health and Life Service and Interest Cost	(1.2)
Effect of One Percent Decrease on Postretirement Health and Life Obligation	$ (17.7)

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

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Pension [Member]

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

Actual Plan Asset Allocation

100.00%

Employer 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

48.00%

52.00%

Plan Asset Target Allocation

56.00%

Pension [Member] | Debt Securities [Member]

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

Actual Plan Asset Allocation

39.00%

34.00%

Plan Asset Target Allocation

35.00%

Pension [Member] | Private Equity [Member]

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

Actual Plan Asset Allocation

8.00%

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

58.00%

^[1]

63.00%

^[1]

Plan Asset Target Allocation

60.00%

^[1]

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

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

Actual Plan Asset Allocation

34.00%

^[1]

29.00%

^[1]

Plan Asset Target Allocation

37.00%

^[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]

8.00%

^[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

3.00%

^[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, 2014

Dec. 31, 2013

Dec. 31, 2012

Pension [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

$ 544.2

$ 501.6

$ 460.1

Pension [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

120.4

234.2

Pension [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

351.6

194.1

Pension [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

72.2

73.3

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

88.5

^[1]

80.2

^[1]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

32.1

^[1]

20.9

^[1]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

56.4

^[1]

59.3

^[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

37.5

^[1]

36.1

^[1]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

13.6

^[1]

9.4

^[1]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

23.9

^[1]

26.7

^[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

38.3

^[1]

38.1

^[1]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

13.9

^[1]

9.9

^[1]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

24.4

^[1]

28.2

^[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

92.0

104.7

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

46.1

61.2

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

45.9

43.5

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Debt Securities - Mutual Funds [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.1

130.1

Pension [Member] | Debt Securities - Mutual Funds [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.1

130.1

Pension [Member] | Debt Securities - Mutual Funds [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Debt Securities - Mutual Funds [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Debt Securities - Fixed Income [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

203.7

36.4

Pension [Member] | Debt Securities - Fixed Income [Member] | Level 1 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

2.7

Pension [Member] | Debt Securities - Fixed Income [Member] | Level 2 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

201.0

36.4

Pension [Member] | Debt Securities - Fixed Income [Member] | Level 3 [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Cash and Cash Equivalents [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

11.9

2.7

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

11.9

2.7

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Pension [Member] | Cash and 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

43.3

46.8

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

43.3

46.8

Pension [Member] | Real Estate [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

28.9

26.5

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

28.9

26.5

Postretirement Health and Life [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

163.2

157.0

131.0

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

140.4

128.4

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

9.9

15.5

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

12.9

13.1

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

29.3

^[2]

28.3

^[2]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

29.3

^[2]

28.3

^[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

20.0

^[2]

17.6

^[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

20.0

^[2]

17.6

^[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

12.6

^[2]

18.2

^[2]

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

12.6

^[2]

18.2

^[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

30.6

33.4

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

30.6

33.4

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] | Debt Securities - Mutual Funds [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

44.5

30.8

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

44.5

30.8

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Debt Securities - Fixed Income [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

9.9

15.5

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

9.9

15.5

Postretirement Health and Life [Member] | Debt Securities - 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

3.4

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

3.4

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] | Cash and Cash Equivalents [Member]

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.1

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

0.1

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

Recurring Fair Value Measures [Line Items]

Fair Value of Assets

Postretirement Health and Life [Member] | Cash and 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

12.9

13.1

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

$ 12.9

$ 13.1

[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, 2014	Dec. 31, 2013
Pension [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	$ 46.8	$ 58.9
Actual Return on Plan Assets	1.2	2.3
Purchases, sales, and settlements, net	(4.7)	(14.4)
Ending Balance	43.3	46.8
Pension [Member] \| Real Estate [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	26.5	24.9
Actual Return on Plan Assets	2.8	2.1
Purchases, sales, and settlements, net	(0.4)	(0.5)
Ending Balance	28.9	26.5
Postretirement Health and Life [Member] \| Private Equity Funds [Member]
Activity in Level 3 [Roll Forward]
Beginning Balance	13.1	13.5
Actual Return on Plan Assets	1.4	2.4
Purchases, sales, and settlements, net	(1.6)	(2.8)
Ending Balance	$ 12.9	$ 13.1

Employee Stock and Incentive Plans - Employee Stock Ownership Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$ 9.1	$ 8.4	$ 7.7
ESOP Shares, Allocated	1.9	2.0	2.2
ESOP Shares, Unallocated	0.3	0.5	0.7
ESOP Shares, Total	2.2	2.5	2.9
Fair Value of Unallocated ESOP Shares	$ 13.2	$ 24.1	$ 28.7

Employee Stock and Incentive Plans - Stock-Based Compensation (Details) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Performance Shares [Member]
Stock-based Compensation [Line Items]
Vesting Period	3 years
Restricted Stock Units [Member]
Stock-based Compensation [Line Items]
Vesting Period	3 years
Employee Stock Purchase Plan (ESPP) [Member]
Stock-based Compensation [Line Items]
ESPP Discount	5.00%
Executive Long-Term Incentive Compensation Plan [Member]
Stock-based Compensation [Line Items]
Common Stock Reserved	0.8
Shares Available for Issuance	0.6

Employee Stock and Incentive Plans - Share-Based Compensation Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	$ 2.3	$ 2.4	$ 2.1
Income Tax Benefit	1.0	1.0	0.9
Capitalized Share-Based Compensation Expense	0	0	0
Performance Shares [Member]
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	1.6	1.7	1.4
Unrecognized Compensation Cost	1.8
Weighted Average Period for Recognition	1 year 7 months 12 days
Restricted Stock Units [Member]
Share-Based Compensation Expense [Line Items]
Share-Based Compensation Expense	0.7	0.7	0.7
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, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2008

Number of Options [Abstract]

Outstanding as of January 1,

108,299

395,678

460,234

Granted

^[1]

Exercised

(42,020)

(287,379)

(49,075)

Forfeited

(15,481)

Outstanding as of December 31,

66,279

108,299

395,678

Exercisable as of December 31,

66,279

108,299

395,678

Weighted Average Exercise Price [Abstract]

Outstanding as of January 1,

$ 44.10

$ 42.28

$ 41.68

Granted

$ 0.00

^[1]

$ 0.00

^[1]

$ 0.00

^[1]

Exercised

$ 43.65

$ 41.60

$ 35.84

Forfeited

$ 0.00

$ 44.86

Outstanding as of December 31,

$ 44.39

$ 44.10

$ 42.28

Exercisable as of December 31,

$ 44.39

$ 43.17

$ 41.71

Weighted Average Grant-Date Intrinsic Value of Options Granted

$ 6.18

Proceeds from Stock Options Exercised

$ 1.8

Total Intrinsic Value of Options Exercised

$ 0.4

$ 2.2

$ 0.3

[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 - Non-Qualified Stock Options, Range of Exercise Price (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
$39.10 to $41.35 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Price, Lower Range Limit	$ 39.10
Range of Exercise Price, Upper Range Limit	$ 41.35
Number Outstanding	21,849
Weighted Average Remaining Contractual Life (in Years)	2 years 10 months 9 days
Weighted Average Exercise Price	$ 39.27
Aggregate Intrinsic Value (Millions)	$ 0.3
Number Exercisable	21,849
Weighted Average Remaining Contractual Life (in Years)	2 years 10 months 9 days
Weighted Average Exercise Price	$ 39.27
Aggregate Intrinsic Value (Millions)	0.3
$44.15 to $48.65 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Price, Lower Range Limit	$ 44.15
Range of Exercise Price, Upper Range Limit	$ 48.65
Number Outstanding	44,430
Weighted Average Remaining Contractual Life (in Years)	1 year 8 months 13 days
Weighted Average Exercise Price	$ 46.90
Aggregate Intrinsic Value (Millions)	0.4
Number Exercisable	44,430
Weighted Average Remaining Contractual Life (in Years)	1 year 8 months 13 days
Weighted Average Exercise Price	$ 46.90
Aggregate Intrinsic Value (Millions)	$ 0.4

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

3 Months Ended

12 Months Ended

3 Months Ended

Mar. 31, 2014

Performance Shares [Member]

Dec. 31, 2014

Performance Shares [Member]

Dec. 31, 2013

Performance Shares [Member]

Dec. 31, 2012

Performance Shares [Member]

Mar. 31, 2014

Restricted Stock Units [Member]

Dec. 31, 2014

Restricted Stock Units [Member]

Dec. 31, 2013

Restricted Stock Units [Member]

Dec. 31, 2012

Restricted Stock Units [Member]

Mar. 31, 2015

Subsequent Event [Member]

Performance Shares [Member]

Mar. 31, 2015

Subsequent Event [Member]

Restricted Stock Units [Member]

Number of Shares [Abstract]

As of January 1,

114,765

107,899

128,333

55,982

56,415

63,464

Granted

43,081

47,992

^[1]

45,830

^[1]

38,764

^[1]

17,491

19,645

^[1]

21,440

^[1]

18,162

^[1]

38,344

15,633

Awarded

(36,515)

(18,605)

(41,009)

(18,860)

(20,939)

(24,707)

(17,815)

Unearned Grant Award

(18,606)

(17,575)

Forfeited

(6,607)

(1,753)

(614)

(2,879)

(934)

(504)

As of December 31,

119,635

114,765

107,899

53,888

55,982

56,415

Weighted Average Grant Date Fair Value [Abstract]

As of January 1,

$ 47.02

$ 40.73

$ 36.54

$ 40.85

$ 36.61

$ 32.57

Granted

$ 46.47

^[1]

$ 52.15

^[1]

$ 44.70

^[1]

$ 48.44

^[1]

$ 43.41

^[1]

$ 40.83

^[1]

Awarded

$ 42.01

$ 35.10

$ 34.25

$ 37.64

$ 32.03

$ 29.43

Unearned Grant Award

$ 0.00

$ 35.10

$ 34.25

Forfeited

$ 48.29

$ 47.26

$ 34.49

$ 45.92

$ 41.02

$ 31.80

As of December 31,

$ 48.26

$ 47.02

$ 40.73

$ 44.47

$ 40.85

$ 36.61

Performance Period

3 years

Grants, Grant Date Fair Value

$ 2.0

$ 0.9

$ 2.3

$ 0.9

Awards, Grant Date Fair Value

$ 1.5

$ 0.7

$ 0

$ 0.7

[1]	Shares granted include 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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data (Unaudited) [Abstract]
Operating Revenue	$ 290.7	$ 288.9	$ 260.7	$ 296.5	$ 268.0	$ 251.0	$ 235.6	$ 263.8
Operating Income	51.5	60.8	28.2	48.3	46.9	38.4	24.4	44.4	188.8	154.1	155.2
Net Income Attributable to ALLETE	$ 32.9	$ 41.6	$ 16.8	$ 33.5	$ 33.0	$ 25.2	$ 14.0	$ 32.5	$ 124.8	$ 104.7	$ 97.1
Basic Earnings Per Share of Common Stock	$ 0.73	$ 0.97	$ 0.40	$ 0.81	$ 0.82	$ 0.63	$ 0.36	$ 0.83	$ 2.91	$ 2.64	$ 2.59
Diluted Earnings Per Share of Common Stock	$ 0.73	$ 0.97	$ 0.40	$ 0.80	$ 0.82	$ 0.63	$ 0.35	$ 0.83	$ 2.90	$ 2.63	$ 2.58

- 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

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- Definition

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

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Schedule II (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Trade Accounts Receivable [Member]

Valuation and Qualifying Accounts and Reserves [Line Items]

Balance at Beginning of Period

$ 1.1

$ 1.0

$ 0.9

Additions, Charged to Income

1.8

1.3

1.0

Additions, Other Charges

Deductions from Reserves

1.8

^[1]

1.2

^[1]

0.9

^[1]

Balance at End of Period

1.1

1.0

Finance Receivables - Long-Term [Member]

Valuation and Qualifying Accounts and Reserves [Line Items]

Balance at Beginning of Period

0.6

Additions, Charged to Income

Additions, Other Charges

Deductions from Reserves

^[1]

Balance at End of Period

0.6

Deferred Tax Assets [Member]

Valuation and Qualifying Accounts and Reserves [Line Items]

Balance at Beginning of Period

8.0

2.4

0.4

Additions, Charged to Income

14.1

5.6

2.0

Additions, Other Charges

Deductions from Reserves

^[1]

Balance at End of Period

$ 22.1

$ 8.0

$ 2.4

[1]	Includes uncollectible accounts written off.

Short-term and Long-term Debt - Financial Covenants (Details)	Dec. 31, 2014
Financial Covenants [Abstract]
Required Indebtedness to Total Capital Ratio	0.65
Actual Indebtedness to Total Capital Ratio	0.47

Commitments, Guarantees and Contingencies - Coal Rail and Shipping Contracts (Details) (Coal and Transportation [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Coal and Transportation [Member]
Coal Rail and Shipping Contracts [Line Items]
Coal Supply and Transportation Agreements, Minimum Annual Payment Obligation in 2015	$ 38.3

Regulatory Matters - Boswell Mercury Emission Reduction Plan (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 250
Capital Cost Spent to Date	$ 145

Acquisitions - ACE Agreement (Details) (ACE Agreement [Member], USD $) In Millions, unless otherwise specified	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2014 MW
ACE Agreement [Member]
Business Acquisition [Line Items]
Member's Interest Purchase Agreement	$ 47.5
Generating Capacity (MW)		97.5

Investments - Investments Parenthetical (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Investments Parenthetical [Abstract]
Long-Term Finance Receivables, Allowance	$ 0.6	$ 0.6

Derivatives - Hedged Items (Details) (Term Loan [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Term Loan [Member]
Debt Instrument [Line Items]
Term Loan Principal Amount	$ 75.0
Percentage of Debt Hedged by Interest Rate Derivatives	5.00%

Commitments, Guarantees and Contingencies - Hydro Operations (Details) (Hydro Project [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Hydro Project [Member]
Hydro Operations [Line Items]
Estimated Capital Expenditures	$ 90