Document and Entity Information Document	9 Months Ended
Document and Entity Information Document	Sep. 30, 2015
Document and Entity Information [Abstract]
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 Common Stock, Shares Outstanding	48,965,562
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Sep. 30, 2015	Dec. 31, 2014
Current Assets [Abstract]
Cash and Cash Equivalents	$ 103.0	$ 145.8
Accounts Receivable (Less Allowance of $1.3 and $1.1)	110.7	103.0
Inventories	119.1	80.5
Prepayments and Other	42.5	82.0
Deferred Income Taxes	28.0	7.5
Total Current Assets	403.3	418.8
Property, Plant and Equipment – Net	3,639.1	3,284.8
Regulatory Assets	353.3	357.3
Investment in ATC	126.0	121.1
Other Investments	113.5	114.4
Goodwill and Intangible Assets – Net	212.9	4.8
Other Non-Current Assets	83.7	59.6
Total Assets	4,931.8	4,360.8
Current Liabilities [Abstract]
Accounts Payable	125.0	134.1
Accrued Taxes	34.8	38.7
Accrued Interest	14.5	18.0
Long-Term Debt Due Within One Year	49.1	100.7
Notes Payable	0	3.7
Other	94.3	120.8
Total Current Liabilities	317.7	416.0
Long-Term Debt	1,549.0	1,272.8
Deferred Income Taxes	593.6	510.7
Regulatory Liabilities	105.8	94.2
Defined Benefit Pension and Other Postretirement Benefit Plans	189.6	190.9
Other Non-Current Liabilities	352.7	265.0
Total Liabilities	3,108.4	2,749.6
Commitments, Guarantees and Contingencies (Note 15)
Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 49.0 and 45.9 Shares Outstanding	1,264.9	1,107.6
Unearned ESOP Shares	(1.4)	(7.2)
Accumulated Other Comprehensive Loss	(20.6)	(21.1)
Retained Earnings	578.8	530.1
Total ALLETE Equity	1,821.7	1,609.4
Non-Controlling Interest in Subsidiaries	1.7	1.8
Total Equity	1,823.4	1,611.2
Total Liabilities and Equity	$ 4,931.8	$ 4,360.8

Consolidated Balance Sheet Parentheticals (USD $) In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2015	Dec. 31, 2014
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.3	$ 1.1
Common Stock [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	49.0	45.9

Consolidated Statement of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Consolidated Statement of Income [Abstract]
Operating Revenue	$ 462.5	$ 288.9	$ 1,105.8	$ 846.1
Operating Expenses [Abstract]
Fuel and Purchased Power	76.8	88.9	242.9	268.7
Transmission Services	13.9	11.9	40.1	33.2
Cost of Sales	149.8	16.8	233.3	59.2
Operating and Maintenance	81.3	65.7	246.4	214.3
Depreciation and Amortization	43.2	33.4	123.5	99.5
Taxes Other than Income Taxes	12.3	11.4	38.5	33.9
Total Operating Expenses	377.3	228.1	924.7	708.8
Operating Income	85.2	60.8	181.1	137.3
Other Income (Expense) [Abstract]
Interest Expense	(17.7)	(13.2)	(49.0)	(39.5)
Equity Earnings in ATC	5.5	5.3	14.1	15.6
Other	1.7	2.1	3.5	6.0
Total Other Expense	(10.5)	(5.8)	(31.4)	(17.9)
Income Before Non-Controlling Interest and Income Taxes	74.7	55.0	149.7	119.4
Income Tax Expense	14.4	13.4	27.0	27.1
Net Income	60.3	41.6	122.7	92.3
Less: Non-Controlling Interest in Subsidiaries	(0.1)	0	(0.1)	0.4
Net Income Attributable to ALLETE	$ 60.4	$ 41.6	$ 122.8	$ 91.9
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (in shares)	48.8	42.9	48.0	42.1
Diluted (in shares)	48.9	42.9	48.1	42.3
Basic Earnings Per Share of Common Stock	$ 1.24	$ 0.97	$ 2.56	$ 2.18
Diluted Earnings Per Share of Common Stock	$ 1.23	$ 0.97	$ 2.55	$ 2.17
Dividends Per Share of Common Stock	$ 0.505	$ 0.49	$ 1.515	$ 1.47

Consolidated Statement of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Comprehensive Income [Abstract]
Net Income	$ 60.3	$ 41.6	$ 122.7	$ 92.3
Other Comprehensive Income [Abstract]
Unrealized Gain (Loss) on Securities, Net of Income Taxes of $(0.4), $–, $(0.3) and $0.1	(0.7)	(0.1)	(0.6)	0.1
Unrealized Gain on Derivatives, Net of Income Taxes of $–, $–, $0.1 and $0.1	0	0.1	0.1	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Net of Income Taxes of $0.3, $0.2, $0.7 and $0.6	0.3	0.2	1.0	0.8
Total Other Comprehensive Income (Loss)	(0.4)	0.2	0.5	1.0
Total Comprehensive Income	59.9	41.8	123.2	93.3
Less: Non-Controlling Interest in Subsidiaries	(0.1)	0	(0.1)	0.4
Comprehensive Income Attributable to ALLETE	$ 60.0	$ 41.8	$ 123.3	$ 92.9

Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Consolidated Statement of Comprehensive Income Parentheticals [Abstract]
Unrealized Gain on Securities, Tax	$ (0.4)	$ 0	$ (0.3)	$ 0.1
Unrealized Gain on Derivatives, Tax	0	0	0.1	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Tax	$ 0.3	$ 0.2	$ 0.7	$ 0.6

Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating Activities [Abstract]
Net Income	$ 122.7	$ 92.3
Allowance for Funds Used During Construction – Equity	(2.6)	(5.9)
Income from Equity Investments – Net of Dividends	(3.7)	(3.0)
Gain on Sales of Investments and Property, Plant and Equipment	(0.2)	(0.2)
Depreciation Expense	120.7	99.5
Amortization of Power Purchase Agreements	(17.1)	(9.0)
Amortization of Other Intangible Assets and Other Assets	5.0	0.8
Deferred Income Tax Expense	26.5	25.2
Share-Based Compensation Expense	2.1	1.7
ESOP Compensation Expense	7.3	6.7
Defined Benefit Pension and Postretirement Benefit Expense	11.5	9.6
Bad Debt Expense	0.8	1.1
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	11.6	16.9
Inventories	(24.1)	(9.2)
Prepayments and Other	(0.4)	8.8
Accounts Payable	0	(1.2)
Other Current Liabilities	(0.8)	(12.8)
Changes in Regulatory and Other Non-Current Assets	(6.2)	(13.0)
Changes in Regulatory and Other Non-Current Liabilities	1.5	3.8
Cash from Operating Activities	254.6	212.1
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	0.7	3.3
Payments for Purchase of Available-for-sale Securities	(1.1)	(4.3)
Acquisitions of Subsidiaries – Net of Cash Acquired	(324.8)	(23.1)
Investment in ATC	(1.2)	(3.1)
Changes to Other Investments	0	31.1
Additions to Property, Plant and Equipment	(208.2)	(467.8)
Cash in Escrow for Acquisition	0	5.4
Proceeds from Sale of Property, Plant and Equipment	0.3	0
Cash for Investing Activities	(534.3)	(458.5)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	155.2	128.9
Proceeds from Issuance of Long-Term Debt	240.0	375.0
Changes in Restricted Cash	2.2	(1.4)
Changes in Notes Payable	(3.7)	2.7
Repayments of Long-Term Debt	(81.8)	(134.1)
Acquisition of Non-Controlling Interest	0	(6.0)
Debt Issuance Costs	(1.0)	(3.1)
Dividends on Common Stock	(74.0)	(62.4)
Cash from Financing Activities	236.9	299.6
Change in Cash and Cash Equivalents	(42.8)	53.2
Cash and Cash Equivalents at Beginning of Period	145.8	97.3
Cash and Cash Equivalents at End of Period	$ 103.0	$ 150.5

Operations and Significant Accounting Policies

9 Months Ended

Sep. 30, 2015

Operations and Significant Accounting Policies [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Reclassifications. As a result of recent acquisitions, certain financial statement captions have been added and we have reclassified certain prior-period amounts on our Consolidated Balance Sheet and Consolidated Statement of Income to conform to the presentation for the current period.

Consolidated Balance Sheet. In conformity with the current presentation of Goodwill and Intangible Assets - Net on the Consolidated Balance Sheet, we have reclassified our December 31, 2014, Consolidated Balance Sheet to include $1.6 million and $3.2 million of goodwill and intangible assets previously disclosed in Property, Plant and Equipment - Net and Other Non-Current Assets, respectively, under Goodwill and Intangible Assets - Net. There was no impact to Total Assets as a result of the reclassification.

Consolidated Statement of Income. In conformity with the current presentation of Cost of Sales on the Consolidated Statement of Income, we have reclassified $16.8 million from Operating and Maintenance expenses to Cost of Sales for the quarter ended September 30, 2014, and $59.2 million for the nine months ended September 30, 2014. Cost of Sales includes purchased gas at SWL&P, expenses incurred to deliver coal at BNI Coal, and the cost of land and other sales at ALLETE Properties. Cost of Sales also includes costs associated with the manufacture and delivery of inventories at U.S. Water Services, our integrated water management company which was acquired on February 10, 2015. (See Note 4. Acquisitions.) In addition to the presentation of Cost of Sales, we have created new captions on the Consolidated Statement of Income to provide additional detail for Transmission Services and Taxes Other than Income Taxes. Transmission Services are MISO-related costs incurred for the transmission of electricity. In conformity with the current presentation, we have reclassified from Operating and Maintenance expenses $11.9 million of Transmission Services and $11.4 million of Taxes Other than Income Taxes for the quarter ended September 30, 2014, and $33.2 million of Transmission Services and $33.9 million of Taxes Other than Income Taxes for the nine months ended September 30, 2014. There was no impact to Operating Income, Net Income, or Net Income Attributable to ALLETE as a result of these reclassifications.

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventories in our Regulated Operations and ALLETE Clean Energy segments are recorded on an average cost basis. Amounts removed from inventories in our U.S. Water Services and Corporate and Other segments are recorded on an average cost, first-in, first-out or specific identification basis.



Inventories	September 30, 2015			December 31, 2014
Millions
Fuel		$54.0			$29.0
Materials and Supplies	52.6			51.5
Raw Materials	3.1			—
Work in Progress	0.7			—
Finished Goods	8.9			—
Reserve for Obsolescence	(0.2		)	—
Total Inventories		$119.1			$80.5

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Prepayments and Other Current Assets	September 30, 2015		December 31, 2014
Millions
Deferred Fuel Adjustment Clause		$16.3		$16.3
Construction Costs for Development Project (a)	—		48.2
Restricted Cash (b)	8.1		2.7
Other	18.1		14.8
Total Prepayments and Other Current Assets		$42.5		$82.0


(a)	Construction Costs for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these costs have been net against contract billings. (See Billings in Excess of Costs and Estimated Earnings in Other Current Liabilities table and Note 4. Acquisitions.)


(b)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities’ operating expense and capital distribution reserve requirements, and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.

Goodwill and Intangible Assets.

Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. To align with the annual budgeting and forecasting process, goodwill is assessed annually in the fourth quarter for impairment and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The estimated fair value is generally determined using a discounted cash flow analysis.

Intangible Assets. Intangible assets include customer relationships, patents, non-compete agreements and trademarks and trade names. Intangible assets with definite lives consist of customer relationships, patents and non-compete agreements, which are amortized on a straight-line or accelerated basis with estimated useful lives ranging from approximately 3 years to approximately 22 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite-lived intangible assets consist of trademarks and trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Fair value is generally determined using a discounted cash flow analysis.

Other Non-Current Assets.

Restricted Cash. Included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $11.9 million and $5.3 million as of September 30, 2015, and December 31, 2014, respectively, related primarily to ALLETE Clean Energy’s wind energy facilities’ major maintenance, debt service, and other reserve requirements.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Current Liabilities	September 30, 2015		December 31, 2014
Millions
Customer Deposits		$17.6		$19.7
Power Purchase Agreements (a)	23.8		19.4
Construction Deposits Received for Development Project (b)	—		54.3
Billings in Excess of Costs and Estimated Earnings (c)	8.8		—
Other	44.1		27.4
Total Other Current Liabilities		$94.3		$120.8


(a)	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)


(b)	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these deposits have been net against contract costs and estimated gross profit. (See Billings in Excess of Costs and Estimated Earnings below and Note 4. Acquisitions.)


(c)	Billings in Excess of Costs and Estimated Earnings represents the excess of contract billings over the construction costs incurred and estimated earnings recognized. In the second quarter of 2015, the NDPSC approved the sale agreement ALLETE Clean Energy has with Montana-Dakota Utilities to develop, construct, and sell a wind energy facility in 2015. (See Note 4. Acquisitions.)



Other Non-Current Liabilities	September 30, 2015		December 31, 2014
Millions
Asset Retirement Obligation		$126.3		$109.2
Power Purchase Agreements (a)	143.9		110.7
Contingent Consideration (b)	37.4		—
Other	45.1		45.1
Total Other Non-Current Liabilities		$352.7		$265.0


(a)	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 4. Acquisitions and Note 6. Fair Value.)

Supplemental Statement of Cash Flows Information.



Nine Months Ended September 30,	2015		2014
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$46.6		$39.4
Cash Paid During the Period for Income Taxes		$0.1		$2.8
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(26.8)		$(6.5)
Capitalized Asset Retirement Costs		$7.8		$0.6
AFUDC–Equity		$2.6		$5.9
ALLETE Common Stock Contributed to the Pension Plan	—			$19.5
Contingent Consideration		$35.7	—

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

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Standards.

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 was effective beginning in the first quarter of 2015, and applies 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 Statements. We will consider the requirements of this standard if future transactions arise.

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 was to have been effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. On July 9, 2015, the FASB decided to defer the effective date of the standard by one year which will make the guidance effective for the Company beginning in the first quarter of 2018. Early adoption is permitted beginning in the first quarter of 2017 for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s Consolidated Financial Statements.

Presentation of Debt Issuance Costs. In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented on the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The adoption of this update is not expected to have a material impact on our Consolidated Financial Statements.

Simplifying the Measurement of Inventory. In July 2015, the FASB issued an accounting standard which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance is effective for the Company beginning in the first quarter of 2017; early adoption is permitted. The adoption of this update is not expected to have a material impact on our Consolidated Financial Statements.

Business Segments

9 Months Ended

Sep. 30, 2015

Business Segments [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

During the quarter ended September 30, 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess, and allocate resources after our recent acquisitions. We will now present three reportable segments, Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. Prior period amounts have been revised to conform with the current business segment presentation.

Regulated Operations includes three operating segments which consist of 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. ALLETE Clean Energy is our business aimed at acquiring or developing capital projects that create energy solutions by way of wind, solar, biomass, hydro, natural gas, shale resources, clean coal technology and other emerging energy innovations. U.S. Water Services is our integrated water management company which was acquired on February 10, 2015. The ALLETE Clean Energy and U.S. Water Services reportable segments comprise our Energy Infrastructure and Related Services businesses. We also present Corporate and Other which includes two operating segments, BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment, along with 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.

NOTE 2. BUSINESS SEGMENTS (Continued)



	Quarter Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015			2014
Millions
Operating Revenue
Regulated Operations	$250.2		$255.8		$743.0			$749.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	151.1		6.8		197.5			22.6
U.S. Water Services	36.1		—		86.0			—

Corporate and Other	25.1		26.3		79.3			73.9
Total Operating Revenue		$462.5		$288.9		$1,105.8			$846.1
Net Income (Loss) Attributable to ALLETE
Regulated Operations (a)		$43.8		$40.9		$108.1			$91.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	13.2		0.5		18.7			1.2
U.S. Water Services	1.0		—		1.5			—

Corporate and Other (a)	2.4		0.2		(5.5		)	(0.9		)
Total Net Income Attributable to ALLETE		$60.4		$41.6		$122.8			$91.9

(a)

During the third quarter of 2015, the Company entered into an intercompany loan agreement, and allocated long-term debt to ALLETE Transmission Holdings, which owns approximately 8 percent of ATC, to better reflect the capital requirements of ALLETE Transmission Holdings and our investment in ATC. ALLETE Transmission Holdings recognized interest expense of approximately $0.3 million after-tax in the third quarter of 2015 which is reflected in our Regulated Operations segment. Our Corporate and Other segment recognized interest income of the same amount. The amounts are eliminated in consolidation. Prior period segment results have been revised to conform to the current presentation as if the intercompany loan existed as of January 1, 2014.



As of September 30,	2015		2014
Millions
Assets
Regulated Operations	$3,836.3		$3,519.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	565.7		184.4
U.S. Water Services	257.8		—

Corporate and Other	272.0		363.6
Total Assets		$4,931.8		$4,067.9

- 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.

+ References

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+ Details

Investments

9 Months Ended

Sep. 30, 2015

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. At September 30, 2015, 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	September 30, 2015		December 31, 2014
Millions
ALLETE Properties		$88.3		$88.2
Available-for-sale Securities (a)	18.5		18.9
Cash Equivalents	2.6		2.9
Other	4.1		4.4
Total Other Investments		$113.5		$114.4


(a)	As of September 30, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $1.6 million, in three years to less than five years was $3.0 million, and in five or more years was $6.4 million.

ALLETE Properties.

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 quarter and nine months ended September 30, 2015 (none for the year ended December 31, 2014).



Available-For-Sale Securities
Millions		Gross Unrealized
	Cost	Gain	Loss	Fair Value
September 30, 2015	$20.1	$0.1	$1.7	$18.5
December 31, 2014	$19.6	$0.2	$0.9	$18.9

		Net	Gross Realized
		Proceeds	Gain	Loss
Quarter Ended September 30,
2015		—	—	—
2014		$0.6	—	—
Nine Months Ended September 30,
2015		$0.7	$0.1	—
2014		$3.3	$0.2	—

Acquisitions

9 Months Ended

Sep. 30, 2015

Acquisitions [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. The pro forma impact of the following acquisitions was not significant, either individually or in the aggregate, to the results of the Company for the nine months ended September 30, 2015, and year ended December 31, 2014.

2015 Activity.

U.S. Water Services. On February 10, 2015, ALLETE acquired U.S. Water Services. Total consideration for the transaction was $202.3 million, which included payment of $166.6 million in cash and an estimated fair value of earnings-based contingent consideration of $35.7 million to be paid through 2019. The contingent consideration is presented within Other Non-Current Liabilities on the Consolidated Balance Sheet. The Consolidated Statement of Income reflects 100 percent of the results of operations for U.S. Water Services since the acquisition date as the Company has acquired 100 percent of U.S. Water Services. U.S. Water Services, an integrated industrial water management company headquartered in St. Michael, Minnesota, provides integrated water management for industry by 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 water and 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 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. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to income taxes; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Cash and Cash Equivalents		$0.9
Accounts Receivable	16.8
Inventories (a)	13.4
Other Current Assets (b)	5.3
Property, Plant and Equipment	10.6
Goodwill (c)	127.7
Intangible Assets (d)	83.0
Other Non-Current Assets	0.2
Total Assets Acquired		$257.9
Liabilities Assumed
Current Liabilities		$19.2
Non-Current Liabilities	36.4
Total Liabilities Assumed		$55.6
Net Identifiable Assets Acquired		$202.3


(a)	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which will be recognized as Cost of Sales within one year from the acquisition date.


(b)	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog will be recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for stand-by letters of credit.


(c)	For tax purposes, the purchase price allocation resulted in $3.2 million of deductible Goodwill.


(d)	Intangible Assets include customer relationships, patents, non-compete agreements and trademarks and trade names. (See Note 5. Goodwill and Intangible Assets.)

Acquisition-related costs of $3.0 million after-tax were expensed as incurred during the first quarter of 2015, and were recorded in Operating and Maintenance on the Consolidated Statement of Income.

NOTE 4. ACQUISITIONS (Continued)

2015 Activity (Continued)

Chanarambie/Viking. On April 15, 2015, ALLETE Clean Energy acquired wind energy facilities in southern Minnesota (Chanarambie/Viking) from EDF Renewable Energy, Inc. for $48.0 million.

The facilities have 97.5 MW of generating capability and are located near ALLETE Clean Energy’s Lake Benton facility. The wind energy facilities began commercial operations in 2003 and have PPAs in place for their entire output, which expire in 2018 (12 MW) and 2023 (85.5 MW).

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 during the third quarter of 2015 to certain assets and liabilities, which are reflected in the table below. The result of these adjustments had no impact on the results of operations for the nine months ended September 30, 2015. Fair value measurements were valued primarily using the discounted cash flow method.



Millions
Assets Acquired
Current Assets		$4.8
Property, Plant and Equipment	103.0
Other Non-Current Assets (a)	1.0
Total Assets Acquired		$108.8
Liabilities Assumed
Current Liabilities (b)		$6.7
Power Purchase Agreements	49.0
Non-Current Liabilities	5.1
Total Liabilities Assumed		$60.8
Net Identifiable Assets Acquired		$48.0


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


(b)	Current Liabilities included $5.9 million related to the current portion of Power Purchase Agreements.

Acquisition-related costs of $0.2 million after-tax were expensed as incurred during the first six months of 2015, and were recorded in Operating and Maintenance on the Consolidated Statement of Income.

Armenia Mountain. On July 1, 2015, ALLETE Clean Energy acquired 100 percent of a wind energy facility located near Troy, Pennsylvania (Armenia Mountain) from The AES Corporation (AES) and a minority shareholder for $111.1 million, plus the assumption of existing debt.

The facility has 100.5 MW of generating capability, began commercial operations in 2009, and has PPAs in place for its entire output, which expire in 2024.

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. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to property, plant and equipment, working capital and PPAs; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method.

NOTE 4. ACQUISITIONS (Continued)

2015 Activity (Continued)



Millions
Assets Acquired
Current Assets (a)	$9.0
Property, Plant and Equipment	156.7
Other Non-Current Assets (b)	14.4
Total Assets Acquired		$180.1
Liabilities Assumed
Current Liabilities		$3.4
Long-Term Debt Due Within One Year	5.9
Long-Term Debt	55.0
Other Non-Current Liabilities	4.7
Total Liabilities Assumed	$69.0
Net Identifiable Assets Acquired		$111.1


(a)	Included in Current Assets was $1.0 million related to the current portion of Power Purchase Agreements and $6.0 million of restricted cash related to capital distribution reserve requirements.


(b)	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of Power Purchase Agreements, $6.1 million of restricted cash related to operating expense and major maintenance reserve requirements, and $0.1 million of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisition-related costs of $1.6 million after-tax were expensed as incurred during the first nine months of 2015, and were recorded in Operating and Maintenance on the Consolidated Statement of Income.

Montana-Dakota Utilities. In November 2014, ALLETE Clean Energy acquired a business for $27.0 million to develop a wind facility near Hettinger, North Dakota. ALLETE Clean Energy is developing and constructing a 107 MW wind facility consisting of 43 turbines, which was approved to be sold to Montana-Dakota Utilities by the NDPSC on June 30, 2015, for approximately $200 million. Construction is expected to be completed in December 2015.

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 $3.6 million and construction in process of $23.4 million. There were no liabilities assumed and no recognition of goodwill.

As a result of the NDPSC approval of the sale agreement with Montana-Dakota Utilities in the second quarter of 2015, ALLETE Clean Energy began accounting for the project under the percentage of completion method of accounting for contracts. The percentage of completion used to recognize revenue and cost of sales is calculated based on the percentage of construction costs incurred at the measurement date compared to the estimated total construction costs. We have selected this method because we consider construction costs to be the best available measure of progress on the project. Any adjustments to the estimated percentage of completion or estimated earnings, and the related impacts to operating income, are recorded in the period they become known.

The following table summarizes contract billings, construction costs, and estimated earnings recognized for the wind facility:



	September 30, 2015
Millions
Contract Billings	$169.7
Construction Costs	137.5
Estimated Earnings	23.4
Billings in Excess of Costs and Estimated Earnings (a)		$8.8


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

NOTE 4. ACQUISITIONS (Continued)

2015 Activity (Continued)

For the nine months ended September 30, 2015, revenue of $156.4 million and cost of sales of $133.0 million were recognized under the percentage of completion method of accounting for contracts and were reported on the Consolidated Statement of Income as Operating Revenue and Cost of Sales, respectively. Cash flows related to construction costs incurred, contract billings, and estimated earnings were reported net on the Consolidated Statement of Cash Flows as Current Liabilities - Other.

As of December 31, 2014, contract billings received were $54.3 million and construction costs incurred (including the construction costs acquired) were $48.2 million and were classified as Current Liabilities - Other and Prepayments and Other, respectively, on the Consolidated Balance Sheet.

2014 Activity.

ACE Wind Acquisition. In January 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 AES for $26.9 million.

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.

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. 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	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
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, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


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


(c)	The purchase price accounting valued the non-controlling interest relating to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method.

In February 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.

NOTE 4. ACQUISITIONS (Continued)

2014 Activity (Continued)

Storm Lake I Acquisition. In December 2014, ALLETE Clean Energy acquired a wind energy facility in Storm Lake, Iowa (Storm Lake I) from NRG Energy, Inc. for $15.1 million.

Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II. The wind energy facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2019.

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 during the first quarter of 2015 to certain assets and liabilities, which are reflected in the table below. The result of these adjustments had no impact on the results of operations for the nine months ended September 30, 2015. 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	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
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)	Current Liabilities included $7.5 million related to the current portion of Power Purchase Agreements.

- 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

Goodwill and Intangible Assets

9 Months Ended

Sep. 30, 2015

Goodwill and Intangible Assets [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The following table summarizes changes to goodwill by business segment for the nine months ended September 30, 2015:



	ALLETE Clean Energy		U.S. Water Services		Total
Millions
Balance as of December 31, 2014		$2.9	—			$2.9
Acquired Goodwill	0.4			$127.7	128.1
Balance as of September 30, 2015		$3.3		$127.7		$131.0

NOTE 5. GOODWILL AND INTANGIBLE ASSETS (Continued)

Balances of intangible assets, net, excluding goodwill as of September 30, 2015, are as follows:



	December 31, 2014		Additions (a)		Amortization	Other (b)	September 30, 2015
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	—			$60.1	$(2.2)	—		$57.9
Developed Technology and Other (c)		$1.9	6.4		(0.6)	$(0.3)	7.4
Total Definite-Lived Intangible Assets	1.9		66.5		(2.8)	(0.3)	65.3
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	—		16.6		n/a	—	16.6
Total Intangible Assets		$1.9		$83.1	$(2.8)	$(0.3)		$81.9


(a)	Additions are primarily the result of the U.S. Water Services acquisition. (See Note 4. Acquisitions.)


(b)	Armenia Mountain was acquired on July 1, 2015, at which time the purchase option intangible asset was reclassified as a component of the acquisition consideration.


(c)	Developed Technology and Other includes patents, non-compete agreements, and land easements.

Customer relationships have a useful life of approximately 22 years and developed technology and other have useful lives ranging from approximately 3 years to approximately 13 years (weighted average of approximately 9 years). The weighted average useful life of all definite-lived intangible assets as of September 30, 2015, is approximately 21 years.

Amortization expense of intangible assets for the nine months ended September 30, 2015, was $2.8 million. Accumulated amortization was $2.9 million and $0.1 million as of September 30, 2015, and December 31, 2014, respectively. The estimated amortization expense for definite-lived intangible assets for the remainder of 2015 is $1.1 million. Estimated annual amortization expense for definite-lived intangible assets is $4.3 million in 2016, $4.2 million in 2017, $4.1 million in 2018, $4.0 million in 2019, and $47.6 million thereafter.

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References+ Details

Fair Value

9 Months Ended

Sep. 30, 2015

Fair Value [Abstract]

Fair Value [Text Block]

FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Descriptions of the three levels of the fair value hierarchy are discussed in Note 10. Fair Value to the Consolidated Financial Statements in our 2014 Form 10-K.

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015, and December 31, 2014. 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.

NOTE 6. FAIR VALUE (Continued)



	Fair Value as of September 30, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.3	—		—			$7.3
Available-for-sale – Corporate Debt Securities	—			$11.2	—		11.2
Cash Equivalents	2.6		—		—		2.6
Total Fair Value of Assets		$9.9		$11.2	—			$21.1

Liabilities:
Deferred Compensation (b)	—			$15.9	—			$15.9
Derivatives – Interest Rate Swap (c)	—		4.8		—		4.8
U.S. Water Services Contingent Consideration (b)	—		—			$37.4	37.4
Total Fair Value of Liabilities	—			$20.7		$37.4		$58.1
Total Net Fair Value of Assets (Liabilities)		$9.9	$(9.5)		$(37.4)		$(37.0)


(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.

NOTE 6. FAIR VALUE (Continued)

The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of September 30, 2015. The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value is measured based on the consideration expected to be transferred, discounted to present value. The discount rate is determined at the time of measurement in accordance with generally accepted valuation methods. The fair value of the acquisition contingent consideration is remeasured to arrive at estimated fair value each reporting period with the change in fair value recognized as income or expense in our Consolidated Statement of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, or in the timing and amount of earnings estimates. Using different valuation assumptions, including earnings projections or discount rates, may result in different fair value measurements and expense (or income) in future periods. The acquisition contingent consideration was measured at $37.4 million as of September 30, 2015.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2014	—
Recognition of U.S. Water Services Contingent Consideration		$35.7
Accretion Expense (a)	1.8
Payments (b)	(0.1		)
Balance as of September 30, 2015		$37.4


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


(b)	Amounts paid to terminated employees.

The Level 3 activity above is the result of the February 10, 2015, acquisition of U.S. Water Services; there was no activity in Level 3 during the year ended December 31, 2014.

For the nine months ended September 30, 2015, and the year ended December 31, 2014, 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 listed below was based on quoted market prices for the same or similar instruments (Level 2).



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
September 30, 2015	$1,598.1	$1,685.2
December 31, 2014	$1,373.5	$1,484.5

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.

Equity Method Investment. Our wholly-owned subsidiary, ALLETE Transmission Holdings, 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. (See Note 8. Investment in ATC.) The aggregate carrying amount of the investment was $126.0 million as of September 30, 2015 ($121.1 million as of December 31, 2014). The Company assesses our investment in ATC for impairment whenever events or changes in circumstances indicate that the carrying amount of our investment in ATC may not be recoverable. For the nine months ended September 30, 2015, and the year ended December 31, 2014, there were no indicators of impairment.

NOTE 6. FAIR VALUE (Continued)

Goodwill. To align with the annual budgeting and forecasting process, the Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Substantially all of the Company’s goodwill is a result of the U.S. Water Services acquisition on February 10, 2015. The aggregate carrying amount of goodwill was $131.0 million and $2.9 million as of September 30, 2015, and December 31, 2014, respectively.

Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. The Company calculates the excess of each reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. As of September 30, 2015, there have been no events or changes in circumstance which would indicate impairment of our goodwill.

Intangible Assets. The Company assesses indefinite-lived intangible assets for impairment annually in the fourth quarter. The Company also assesses indefinite-lived and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable. Substantially all of the Company’s intangible assets are a result of the U.S. Water Services acquisition on February 10, 2015. The aggregate carrying amount of intangible assets was $81.9 million as of September 30, 2015 ($1.9 million as of December 31, 2014). When events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable, the Company calculates the excess of an intangible asset's carrying amount over its undiscounted future cash flows. If the carrying amount is not recoverable, an impairment loss is recorded based on the amount by which the carrying amount exceeds the fair value. The inputs used in the fair value analysis fall within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs to determine fair value. As of September 30, 2015, there have been no events or changes in circumstance which would indicate impairment of our intangible assets.

Property, Plant and Equipment. The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable. For the nine months ended September 30, 2015, and the year ended December 31, 2014, there were no indicators of impairment.

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to natural gas in the second quarter of 2015, which were actions included in our 2013 Integrated Resource Plan approved by the MPUC in a November 2013 order. On September 1, 2015, Minnesota Power filed its 2015 Integrated Resource Plan with the MPUC which contains the next steps its EnergyForward plan, which includes the economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016 and the ceasing of coal-fired operations at Taconite Harbor in 2020. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor or the conversion of Laskin. In addition, we expect to be able to continue depreciation of these assets over their established remaining useful lives; however we are unable to predict the impact of unanticipated regulatory outcomes resulting in changes to their remaining useful lives. We would seek recovery in a general rate case of additional depreciation expense as a result of material changes in useful lives.

- Definition

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

+ References+ Details

Regulatory Matters

9 Months Ended

Sep. 30, 2015

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.

Energy-Intensive Trade-Exposed Customer Rates. The Minnesota Legislature enacted, and the Governor of Minnesota signed, Energy-Intensive Trade-Exposed customer ratemaking legislation in June 2015. The intent of this legislation is to enable the MPUC to address elements in rate design to better support the competitiveness of manufacturers with electrically intensive operations which compete in global markets. The Company is working with stakeholders to develop a rate schedule to be filed with the MPUC. It is expected that any rate design outcomes will be implemented on a revenue neutral basis.

NOTE 7. REGULATORY MATTERS (Continued)

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.

On April 21, 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. The electric service agreements with the Brainerd Public Utilities Commission 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 Minnesota Power’s 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.

In September 2015, Minnesota Power amended its wholesale electric contracts with the remaining 14 municipal customers, extending the contract terms through December 31, 2024. These contracts include fixed capacity charges through 2018; beginning January 1, 2019, the capacity charge will not increase by more than two percent or decrease by more than one percent from the previous year’s capacity charge and will be based on a cost-based formula methodology. The energy charge for each year of the contract term will be set each January 1 and is also based on a cost-based formula methodology.

All of the wholesale contracts 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, 2025. Under the agreements with the Brainerd Public Utilities Commission and SWL&P, no termination notices may be given prior to June 30, 2016. The remaining 14 municipal customers may not give termination notices prior to December 31, 2021.

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 an order dated February 23, 2015, 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. On May 22, 2015, Minnesota Power filed a transmission factor filing which includes updated costs associated with certain transmission facilities. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills. As a result of the MPUC approval of the certificate of need for the GNTL on June 30, 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power anticipates including its portion of the investments and expenditures for the GNTL as part of future transmission factor filings to include updated billing rates on customer bills.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to the 497 MW Bison Wind Energy Center in North Dakota. Customer billing rates for the Bison Wind Energy Center were approved by the MPUC in an order dated May 22, 2015. In November 2014, Minnesota Power filed a renewable resources factor filing which includes updated costs associated with Bison. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

On February 13, 2015, Minnesota Power supplemented its November 2014 renewable resources factor filing to include costs associated with the restoration and repair of Thomson. In an order dated March 5, 2015, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which detailed its EnergyForward strategic plan and included 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 underway at Boswell Unit 4, planning for the proposed GNTL, the conversion of Laskin from coal to natural gas completed in June 2015 and the retirement of Taconite Harbor Unit 3 completed in May 2015. On September 1, 2015, Minnesota Power filed its 2015 Integrated Resource Plan with the MPUC which contains the next steps in its EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation in the next decade.

NOTE 7. REGULATORY MATTERS (Continued)

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. 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 $260 million, of which approximately $207 million was spent through September 30, 2015. Project completion is expected in the first quarter of 2016. In a November 2013 order, the MPUC approved the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Customer billing rates for the environmental improvement rider were approved by the MPUC in an order dated August 24, 2015. On September 30, 2015, Minnesota Power filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

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 which was approved in an order dated June 30, 2015. Based on this order, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission factor filings. In April 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 a July 2014 order, the MPUC determined the route permit application to be complete. On October 30, 2015, the Minnesota Department of Commerce and the U.S. Department of Energy released the final EIS for the GNTL. A decision on the route permit by the MPUC is expected in the first quarter of 2016. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to Manitoba Conservation and Water Stewardship for regulatory approval. 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 expected to begin by 2017 and to be completed in 2020.

Conservation Improvement Program (CIP). Minnesota has enacted legislation establishing an annual energy-savings goal for each utility of 1.5 percent of annual retail energy sales. On April 1, 2015, Minnesota Power submitted its 2014 CIP filing that requested a CIP financial incentive of $6.2 million based upon MPUC procedures. The requested CIP financial incentive was approved by the MPUC in an order dated September 16, 2015, and was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2015 and 2016. In 2014, the CIP financial incentive of $8.7 million was recognized in the third quarter. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

MISO Return on Equity Complaints. In November 2013, several customer groups located within the MISO service area filed complaints with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ALLETE, to 9.15 percent. On February 12, 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. As a result of these complaints filed with the FERC, we have recorded an estimated refund obligation for MISO revenue of $6.2 million and an estimated refund for MISO transmission expense of $4.1 million, resulting in a reserve of $2.1 million as of September 30, 2015; $1.5 million was attributable to prior years.

Regulatory Assets and Liabilities. Our regulated utility operations are subject to 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 7. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	September 30, 2015		December 31, 2014
Millions
Current Regulatory Assets (a)
Deferred Fuel		$16.3		$16.3
Total Current Regulatory Assets	16.3		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	212.3		223.9
Cost Recovery Riders (c)	64.0		59.7
Income Taxes	46.9		46.6
Asset Retirement Obligations	20.5		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	4.6		4.3
Total Non-Current Regulatory Assets	353.3		357.3
Total Regulatory Assets		$369.6		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$54.5		$42.9
Plant Removal Obligations	20.9		22.8
Income Taxes	12.8		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	1.8		3.5
Other	15.8		11.6
Total Non-Current Regulatory Liabilities		$105.8		$94.2


(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 14. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are primarily due to capital expenditures related to the 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

9 Months Ended

Sep. 30, 2015

Investment in ATC [Abstract]

Investment in ATC [Text Block]

INVESTMENT IN ATC

Our wholly-owned subsidiary, ALLETE Transmission Holdings, 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. We account for our investment in ATC under the equity method of accounting. As of September 30, 2015, our equity investment in ATC was $126.0 million ($121.1 million at December 31, 2014). In the first nine months of 2015, we invested $1.2 million in ATC, and on October 29, 2015, we invested an additional $0.4 million. We do not expect to make any additional investments in 2015.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2014		$121.1
Cash Investments	1.2
Equity in ATC Earnings	14.1
Distributed ATC Earnings	(10.4		)
Equity Investment Balance as of September 30, 2015		$126.0

NOTE 8. INVESTMENT IN ATC (Continued)

ATC’s summarized financial data for the quarter and nine months ended September 30, 2015 and 2014, is as follows:



	Quarter Ended				Nine Months Ended
ATC Summarized Financial Data	September 30,				September 30,
Income Statement Data	2015		2014		2015		2014
Millions
Revenue		$164.5		$163.6		$482.0		$487.0
Operating Expense	78.0		76.6		238.3		229.6
Other Expense	23.1		21.4		71.7		65.1
Net Income		$63.4		$65.6		$172.0		$192.3
ALLETE’s Equity in Net Income		$5.5		$5.3		$14.1		$15.6

Our equity earnings in ATC for the nine months ended September 30, 2015, were $14.1 million and reflected a $2.0 million reduction related to complaints filed with the FERC by several customer groups located within the MISO service area; of which $1.1 million was attributable to ATC’s change in estimate of a refund liability relating to prior years. The groups requested, 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. On February 12, 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. 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 ($0.9 million pre-tax).

- 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

Short-Term and Long-Term Debt

9 Months Ended

Sep. 30, 2015

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 September 30, 2015, total short-term debt outstanding was $49.1 million and consisted of long-term debt due within one year. Short-term debt outstanding as of December 31, 2014, was $104.4 million and consisted of long-term debt due within one year and notes payable.

Long-Term Debt. As of September 30, 2015, total long-term debt outstanding was $1,549.0 million ($1,272.8 million as of December 31, 2014).

On July 1, 2015, ALLETE Clean Energy assumed $60.9 million of long-term debt at fair value, including $5.9 million due within one year, in conjunction with ALLETE Clean Energy’s acquisition of Armenia Mountain. (See Note 4. Acquisitions.)

On August 25, 2015, the Company entered into a $125.0 million Term Loan Agreement with JPMorgan Chase Bank, N.A., as a lender and administrative agent, and Bank of America, N.A., as a lender (Term Loan). The Term Loan is an unsecured, single-draw loan that is due on August 25, 2017. The interest rate on the Term Loan is equal to LIBOR plus 0.625 percent. Proceeds from the Term Loan will be used for general corporate purposes, including the refinancing of the $75.0 million Term Loan Agreement due August 25, 2015.

The Term Loan contains customary conditions of borrowing, events of default and affirmative and negative covenants. The Term Loan includes a financial covenant to maintain a ratio of total indebtedness to total capitalization (as defined therein) equal to or less than 65 percent. Indebtedness under the Term Loan may be accelerated upon the occurrence of an event of default, including cross-default to other indebtedness in excess of $35.0 million.

NOTE 9. SHORT-TERM AND LONG-TERM DEBT (Continued)

On September 24, 2015, we issued $100.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:



Maturity Date	Principal Amount	Interest Rate
September 15, 2020	$40 Million	2.80%
September 16, 2030	$60 Million	3.86%

Interest on the Bonds is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2016. The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision; however, the September 16, 2030, series of bonds is redeemable at par, including 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 intends to use the proceeds from the sale of the Bonds to 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.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of September 30, 2015, 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 September 30, 2015, ALLETE was in compliance with its financial covenants.

Income Tax Expense

9 Months Ended

Sep. 30, 2015

Income Tax Expense [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended					Nine Months Ended
	September 30,					September 30,
	2015		2014			2015			2014
Millions
Current Tax Expense
Federal (a)	—		—			—			—
State (a) (b)	$0.2		$1.8				$0.5		$1.9
Total Current Tax Expense	$0.2		$1.8				$0.5		$1.9
Deferred Tax Expense (Benefit)
Federal	$14.8			$11.2		$23.5				$20.4
State	(0.4	)	0.7			3.6			5.4
Investment Tax Credit Amortization	(0.2	)	(0.3		)	(0.6		)	(0.6		)
Total Deferred Tax Expense	14.2		11.6			26.5			25.2
Total Income Tax Expense	$14.4			$13.4		$27.0				$27.1


(a)	For the quarter and nine months ended September 30, 2015, the federal and state current tax expense was minimal due to the utilization of NOL carryforwards from prior periods. The NOL carryforwards resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.


(b)	For the quarter and nine months ended September 30, 2014, the state current tax expense reflected initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired due to NOL carryforwards from prior periods. State NOL and alternative minimum tax carryforwards remaining after utilization in 2015 will be carried forward to offset future income.

The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate, and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.

For the nine months ended September 30, 2015, the effective tax rate was 18.0 percent (22.7 percent for the nine months ended September 30, 2014). The decrease in the effective tax rate from September 30, 2014, was primarily due to increased production tax credits. The effective rate deviated from the statutory rate of approximately 41 percent primarily due to production tax credits.



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Nine Months Ended September 30	2015			2014
Millions
Income Before Non-Controlling Interest and Income Taxes		$149.7			$119.4
Statutory Federal Income Tax Rate	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate	52.4			41.8
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	2.6			4.8
Production Tax Credits	(27.0		)	(16.4		)
Regulatory Differences for Utility Plant	(0.7		)	(2.1		)
Other	(0.3		)	(1.0		)
Total Income Tax Expense		$27.0			$27.1

Uncertain Tax Positions. As of September 30, 2015, we had gross unrecognized tax benefits of $2.9 million ($2.0 million as of December 31, 2014). Of the total gross unrecognized tax benefits, $0.4 million represents the amount of unrecognized tax benefits included in the Consolidated Balance Sheet that, if recognized, would favorably impact the effective income tax rate. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the 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 is no longer subject to federal examination for years before 2012, or state examination for years before 2010.

- 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)

9 Months Ended

Sep. 30, 2015

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

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

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive income (loss), net of tax, for the quarters ended September 30, 2015 and 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
Quarter Ended September 30, 2015
Beginning Accumulated Other Comprehensive Loss	$(0.2)		$(20.0)		—	$(20.2)
Other Comprehensive Loss Before Reclassifications	(0.7)		—		—	(0.7	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		0.3		—	0.3
Net Other Comprehensive Income (Loss)	(0.7)		0.3		—	(0.4	)
Ending Accumulated Other Comprehensive Loss	$(0.9)		$(19.7)		—	$(20.6)

Quarter Ended September 30, 2014
Beginning Accumulated Other Comprehensive Income (Loss)	$0.1		$(16.1)		$(0.3)	$(16.3)
Other Comprehensive Income (Loss) Before Reclassifications	(0.1	)	(0.1	)	0.1	(0.1	)
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	—		0.3		—	0.3
Net Other Comprehensive Income (Loss)	(0.1	)	0.2		0.1	0.2
Ending Accumulated Other Comprehensive Loss	—		$(15.9)		$(0.2)	$(16.1)

Reclassifications from accumulated other comprehensive income (loss) for the quarters ended September 30, 2015 and 2014, were as follows:



	Quarter Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	September 30,		September 30,
	2015		2014
Millions
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (a)	$0.1		$0.1
Actuarial Gains and Losses (a)	(0.6)		(0.6	)
Total	(0.5	)	(0.5	)
Income Taxes (b)	0.2		0.2
Total, Net of Income Taxes	$(0.3)		$(0.3)
Total Reclassifications	$(0.3)		$(0.3)


(a)	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 14. Pension and Other Postretirement Benefit Plans.)


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

NOTE 12. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

Changes in accumulated other comprehensive income (loss), net of tax, for the nine months ended September 30, 2015 and 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
Nine Months Ended September 30, 2015
Beginning Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)		$(0.1)	$(21.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.5)		0.1		0.1	(0.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1)		0.9		—	0.8
Net Other Comprehensive Income (Loss)	(0.6)		1.0		0.1	0.5
Ending Accumulated Other Comprehensive Loss	$(0.9)		$(19.7)		—	$(20.6)

Nine Months Ended September 30, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)		$(0.3)	$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	0.2		(0.1	)	0.1	0.2
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1	)	0.9		—	0.8
Net Other Comprehensive Income	0.1		0.8		0.1	1.0
Ending Accumulated Other Comprehensive Loss	—		$(15.9)		$(0.2)	$(16.1)

Reclassifications from accumulated other comprehensive income (loss) for the nine months ended September 30, 2015 and 2014, were as follows:



	Nine Months Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	September 30,			September 30,
	2015			2014
Millions
Unrealized Gains on Available-for-sale Securities (a)		$0.1			$0.2
Income Taxes (b)	—			(0.1		)
Total, Net of Income Taxes		$0.1			$0.1

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.3			$0.3
Actuarial Gains and Losses (c)	(1.9		)	(1.8		)
Total	(1.6		)	(1.5		)
Income Taxes (b)	0.7			0.6
Total, Net of Income Taxes	$(0.9)			$(0.9)
Total Reclassifications	$(0.8)			$(0.8)


(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 14. 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

Earnings Per Share and Common Stock

9 Months Ended

Sep. 30, 2015

Earnings Per Share and Common Stock [Abstract]

Earnings Per Share and Common Stock [Text Block]

EARNINGS PER SHARE AND COMMON STOCK

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. 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). For the nine months ended September 30, 2015 and 2014, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share.



			2015					2014
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Quarter ended September 30,
Net Income Attributable to ALLETE		$60.4			$60.4		$41.6			$41.6
Average Common Shares	48.8		0.1	48.9		42.9		—	42.9
Earnings Per Share		$1.24			$1.23		$0.97			$0.97
Nine months ended September 30,
Net Income Attributable to ALLETE		$122.8			$122.8		$91.9			$91.9
Average Common Shares	48.0		0.1	48.1		42.1		0.2	42.3
Earnings Per Share		$2.56			$2.55		$2.18			$2.17

Forward Sale Agreement and Issuance of Common Stock. In February 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.

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock from third parties and sold them to the underwriters. The forward sale price was $48.01 per share, subject to adjustment as provided in the Agreement. In September 2014, ALLETE physically settled a portion of its obligations under the Agreement by delivering approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million and on February 4, 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.4 million.

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 in March 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.

Contributions to Pension. No contributions were made to the pension plan for the nine months ended September 30, 2015. For the nine months ended September 30, 2014, ALLETE contributed 0.4 million shares of ALLETE common stock to its pension plan. 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, and had an aggregate value of $19.5 million when contributed.

- Definition

The entire disclosure for earnings per share.

+ References+ Details

Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2015

Pension and Other Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2015			2014			2015		2014
Millions
Quarter Ended September 30,
Service Cost	$2.6				$2.0		$1.0			$0.9
Interest Cost	7.5			7.5			1.8		1.8
Expected Return on Plan Assets	(10.2		)	(9.6		)	(2.7	)	(2.5		)
Amortization of Prior Service Costs (Credits)	—			0.1			(0.7	)	(0.7		)
Amortization of Net Loss	4.4			3.6			0.1		0.1
Net Periodic Benefit Expense (Income)		$4.3			$3.6		$(0.5)		$(0.4)

Nine Months Ended September 30,
Service Cost	$7.6				$6.2		$3.2			$2.6
Interest Cost	22.4			22.4			5.4		5.5
Expected Return on Plan Assets	(30.5		)	(28.7		)	(8.2	)	(7.7		)
Amortization of Prior Service Costs (Credits)	0.1			0.2			(2.2	)	(1.9		)
Amortization of Net Loss	13.4			10.7			0.3		0.3
Net Periodic Benefit Expense (Income)		$13.0			$10.8		$(1.5)		$(1.2)

Employer Contributions. For the nine months ended September 30, 2015, no contributions were made to our defined benefit pension plan ($19.5 million for the nine months ended September 30, 2014); we do not expect to make any contributions to our defined benefit pension plan in 2015. For the nine months ended September 30, 2015 and 2014, we made no contributions to our other postretirement benefit plan; we do not expect to make any contributions to our other postretirement benefit plan in 2015.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References+ Details

Commitments, Guarantees and Contingencies

9 Months Ended

Sep. 30, 2015

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 Minnesota Power’s 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 its entitlement to Unit output. Minnesota Power’s 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 September 30, 2015, Square Butte had total debt outstanding of $377.9 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 Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Coal under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during the nine months ended September 30, 2015, was $57.6 million ($51.8 million for the nine months ended September 30, 2014). 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 $7.6 million during the nine months ended September 30, 2015 ($7.9 million for the nine months ended September 30, 2014). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced in June 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. In 2015, Minnesota Power’s portion of output sold to Minnkota Power is approximately 28 percent (23 percent in 2014).

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 energy 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.

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. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the additional transmission capacity in Canada to Manitoba Conservation and Water Stewardship for regulatory approval. 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 pricing under this PPA is based on forward market prices. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL. (See Great Northern Transmission Line.)

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.

TransAlta PPAs. In September 2015, Minnesota Power and TransAlta signed PPAs that provide for Minnesota Power to purchase 50 MW of energy during off-peak hours and 100 MW of energy during on-peak hours beginning in January 2017 and ending in December 2019. The energy prices are fixed throughout the terms of the PPAs.

Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2016 and a portion of its coal requirements through December 2019. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018. The minimum annual payment obligation under these supply and transportation agreements is $13.9 million for the remainder of 2015, $37.4 million in 2016, $27.6 million in 2017, $28.3 million in 2018 and $1.8 million in 2019. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term, which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2022. The aggregate amount of minimum lease payments for all operating leases is $15.0 million in 2015, $12.9 million in 2016, $11.8 million in 2017, $10.4 million in 2018, $9.3 million in 2019 and $29.1 million thereafter.

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 an order dated February 23, 2015, 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. On May 22, 2015, Minnesota Power filed a transmission factor filing which includes updated costs associated with certain transmission facilities. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills. As a result of the MPUC approval of the certificate of need for the GNTL on June 30, 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power anticipates including its portion of the investments and expenditures for the GNTL as part of future transmission factor filings to include updated billing rates on customer bills.

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.

On April 2, 2015, the CapX2020 transmission line project from Fargo, North Dakota, to St. Cloud, Minnesota, was completed and placed into service. Minnesota Power previously participated in two additional CapX2020 projects which were completed and placed into service in 2011 and 2012.

Minnesota Power invested approximately $100 million to complete the three transmission line projects. 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.

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a certificate of need application was filed with the MPUC which was approved in an order dated June 30, 2015. Based on this order, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission factor filings. In April 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 a July 2014 order, the MPUC determined the route permit application to be complete. On October 30, 2015, the Minnesota Department of Commerce and the U.S. Department of Energy released the final EIS for the GNTL. A decision on the route permit by the MPUC is expected in the first quarter of 2016. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to Manitoba Conservation and Water Stewardship for regulatory approval. 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 expected to begin by 2017 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 the U.S. 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 and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in April 2011 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) in September 2014. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at certain small coal units, and the addition of 200 MW of wind energy. Provisions of the Consent Decree require that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted through existing emission control technology at Boswell. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. Minnesota Power’s 2015 Integrated Resource Plan filed with the MPUC on September 1, 2015, outlined Minnesota Power’s preferred option to reroute emissions from Units 1 and 2 through existing emission control technology at Boswell Unit 3. 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). In April 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 in June 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. In October 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 a total of 28 states in the eastern half of the United States, including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. 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 are 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.

NOTE 15. 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 were required to be in compliance with the rule by April 2015. States had the authority to grant sources a one-year extension. The MPCA approved Minnesota Power’s request for an extension of 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 $260 million, of which approximately $207 million was spent through September 30, 2015. Project completion is expected in the first quarter of 2016. Boswell Unit 3 is also subject to the MATS rule; however, investments and compliance work completed at Boswell Unit 3, including the emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to natural gas in June 2015 positioned those units for MATS compliance. In January 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 retirement at Unit 3 with MISO’s resource planning year. Taconite Harbor Unit 3 was retired in May 2015.

On June 29, 2015, the U.S. Supreme Court reversed and remanded an earlier U.S. Court of Appeals for the D.C. Circuit decision on the MATS rule. The U.S. Supreme Court ruled that it was unreasonable for the EPA to deem cost of compliance irrelevant in determining that regulation of emissions of hazardous air pollutants from power plants was “appropriate and necessary” under Section 112 of the Clean Air Act. The MATS rule remains in effect until the U.S. Court of Appeals for the D.C. Circuit acts on the remand. The U.S. Supreme Court decision is not expected to have a material impact on Minnesota Power generation due to ongoing emission reduction obligations under the Minnesota Mercury Emissions Reduction Act and the Consent Decree. (See New Source Review.)

Minnesota Mercury Emissions Reduction Act/Rule. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, which was incorporated into rules promulgated by the MPCA in September 2014, 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 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 the costs for complying with the final rule are not expected to be material.

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 the 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 of 75 parts per billion (ppb) and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. On October 1, 2015, the EPA released the final rule revising the eight-hour ozone standard to 70 ppb with a secondary standard also set at 70 ppb. All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data. However, some areas in the metropolitan Twin Cities and southwest portion of the state are close to exceeding the standard, so voluntary efforts to reduce ozone continue in the state. No additional costs for compliance are anticipated at this time.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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.

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, and issued designations of the 2012 revised primary annual fine particulate attainment status in December 2014. The EPA designated the entire state of Minnesota as unclassifiable/attainment; 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 is likely in compliance with these standards; however, the one-hour SO₂ NAAQS also requires the EPA to evaluate additional modeling and monitoring considerations 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 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 delayed completing the documents pending EPA guidance to states for preparing the SIP submittal.

In September 2013 the EPA provided guidance to states regarding implementation of the one-hour NO₂ NAAQS and in June 2014, as clarified on February 3, 2015, the MPCA submitted a SIP revision to the EPA addressing the infrastructure requirements of Sections 110(a)(1) and 110(a)(2) of the Clean Air Act in regards to the one-hour NO₂ and SO₂ NAAQS, among other standards. The SIP stated that since the EPA determined in January 2012 that no area in the country is in violation of the one-hour NO₂ NAAQS, there are no nonattainment areas in the country for this pollutant, and therefore Minnesota’s NO₂ emissions cannot be significantly contributing to nonattainment in any other state. On October 20, 2015, the EPA published in the Federal Register an approval and partial disapproval of the June 2014 SIP revision. According to the MPCA, the partial disapproval is regarding state delegation of a program unrelated to the one-hour NAAQS for SO₂ and NO_2,and is not expected to require further action. As such, additional compliance costs for the one-hour NO₂ NAAQS are not expected at this time.

On August 10, 2015, the EPA finalized the SO₂ data requirements rule (DRR) for the 2010 one-hour NAAQS to assist the states in implementing the standard. The rule sets emissions thresholds and exemptions for facilities that trigger modeling requirements. Boswell and Taconite Harbor are the only Minnesota Power generating facilities subject to the DRR. The MPCA informed Minnesota Power that compliant SO₂ modeling recently completed at these facilities should satisfy the DRR obligations, and no further modeling should be required. The MPCA is in discussion with the EPA to confirm its conclusion. The MPCA is required to inform the EPA which sources are subject to the rule by January 15, 2016, and how each source will evaluate air quality by July 1, 2016. As such, additional compliance costs for the one-hour SO₂ NAAQS are not expected at this time.

Class I Air Quality Petitions and Requests. In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Fond du Lac Band) announced its intent to petition 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 Fond du Lac Band does not currently possess authority to directly regulate air quality. Class I air shed status, if granted, would allow the Fond du Lac 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 Fond du Lac Band in October 2014, and the extended public comment period on the petition expired in November 2014. After the Fond du Lac Band prepares responses to the comments, it is anticipated to make a formal submittal request to the EPA. The Company has requested additional clarification from the Fond du Lac Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In May 2013, the Bad River Band of Lake Superior Chippewa (Bad River Band) announced its intent to petition the EPA to redesignate its reservation air shed, which is located approximately 100 miles east of Duluth, Minnesota, from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Class I analysis report was issued by the Bad River Band in January 2015 which was followed by public hearings in March 2015 and a public comment period ending in May 2015. After the Bad River Band prepares responses to the comments, it is also anticipated to make a formal submittal request to the EPA.

There is no deadline for the approval, denial, or modification of these requests by the EPA. 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.

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.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 issued the final CPP on August 3, 2015, together with a proposed federal implementation plan and a model rule for emissions trading. The CPP establishes uniform CO₂ emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO₂ emissions from the power sector. State goals were determined based on CPP source-specific performance emission rates and each state’s mix of power plants.

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). BSER is comprised of three 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, and 3) building more zero- and low-emitting power sources, including renewable energy. States may also choose to include avoided CO₂ emissions from customer energy efficiency measures for credit towards meeting state goals.

State goals under the CPP are expressed as both mass-based and rate-based goals, and include interim goals to be met over the years 2022 through 2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state is required to develop a state implementation plan by September 6, 2016, or by September 6, 2018, if granted an extension. In developing its plan, a state may choose to meet either the mass-based or the rate-based goals. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company.

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 7. Regulatory Matters.)

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

Minnesota’s Next Generation Energy Act of 2007. In April 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 in May 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 in August 2014, with an effective date in October 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 NPDES permits have been re-issued containing Section 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 limit guidelines (ELG) for steam electric power generating stations under the Clean Water Act. The final ELG was issued on September 30, 2015. It sets effluent limits and prescribes BACT for several wastewater streams, including flue gas desulphurization (FGD) water and coal combustion landfill leachate. The ELG rule also prohibits the discharge of bottom and fly ash contact waters. Compliance with the final rule is required between November 1, 2018, and December 31, 2023.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

We are reviewing the proposed rule and evaluating its potential impact on Minnesota Power’s operations, primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not currently discharge, but may do so in the future. Under the final ELG rule, bottom ash discharge would not be allowed and bottom ash contact water would either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system would need to be converted to a dry process. If the FGD wastewater is discharged in the future, it would require additional wastewater treatment. Efforts have been underway at Boswell for several years to reduce the amount of water discharged and evaluate potential re-use options in its plant processes. Additional efforts are underway to determine if land application of certain wastewater streams under a state disposal system may be feasible.

At this time, we cannot estimate what 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. Minnesota Power 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 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).

The EPA issued the final CCR rule in December 2014 under Subtitle D (non-hazardous) of RCRA which was published in the Federal Register on April 27, 2015. 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 for Boswell and Laskin could be up to approximately $100 million. Minnesota Power does not plan on disposing ash onsite at Taconite Harbor after the effective date of the rule, and therefore, the CCR rule will not be applicable to that generating facility. Minnesota Power continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. Minnesota Power would seek recovery of any additional costs through a general rate case.

Other Matters.

ALLETE Clean Energy. ALLETE Clean Energy acquired wind energy facilities in 2014 and 2015, which have PPAs in place for their entire output and expire in various years between 2018 and 2032. (See Note 4. Acquisitions.)

U.S. Water Services. As of September 30, 2015, U.S. Water Services has $0.8 million outstanding in stand-by letters of credit.

BNI Coal. As of September 30, 2015, BNI Coal had surety bonds outstanding of $49.9 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 $47.5 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 September 30, 2015, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.8 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $6.2 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

NOTE 15. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Community Development District Obligations. At September 30, 2015, we owned 72 percent of the assessable land in the Town Center District (72 percent at December 31, 2014) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2014). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds 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.

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.

Operations and Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Operations and Significant Accounting Policies [Abstract]
Reclassification [Policy Text Block]	As a result of recent acquisitions, certain financial statement captions have been added and we have reclassified certain prior-period amounts on our Consolidated Balance Sheet and Consolidated Statement of Income to conform to the presentation for the current period.
Inventories [Policy Text Block]	Inventories are stated at the lower of cost or market. Amounts removed from inventories in our Regulated Operations and ALLETE Clean Energy segments are recorded on an average cost basis. Amounts removed from inventories in our U.S. Water Services and Corporate and Other segments are recorded on an average cost, first-in, first-out or specific identification basis.
Goodwill [Policy Text Block]	Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. To align with the annual budgeting and forecasting process, goodwill is assessed annually in the fourth quarter for impairment and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The estimated fair value is generally determined using a discounted cash flow analysis.
Intangible Assets [Policy Text Block]	Intangible assets include customer relationships, patents, non-compete agreements and trademarks and trade names. Intangible assets with definite lives consist of customer relationships, patents and non-compete agreements, which are amortized on a straight-line or accelerated basis with estimated useful lives ranging from approximately 3 years to approximately 22 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite-lived intangible assets consist of trademarks and trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Fair value is generally determined using a discounted cash flow analysis.
Subsequent Events [Policy Text Block]	The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.
New Accounting Standards [Policy Text Block]	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 was effective beginning in the first quarter of 2015, and applies 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 Statements. We will consider the requirements of this standard if future transactions arise. 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 was to have been effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. On July 9, 2015, the FASB decided to defer the effective date of the standard by one year which will make the guidance effective for the Company beginning in the first quarter of 2018. Early adoption is permitted beginning in the first quarter of 2017 for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s Consolidated Financial Statements. Presentation of Debt Issuance Costs. In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented on the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The adoption of this update is not expected to have a material impact on our Consolidated Financial Statements. Simplifying the Measurement of Inventory. In July 2015, the FASB issued an accounting standard which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance is effective for the Company beginning in the first quarter of 2017; early adoption is permitted. The adoption of this update is not expected to have a material impact on our Consolidated Financial Statements.
Land Inventory [Policy Text Block]	Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairments were recorded for the quarter and nine months ended September 30, 2015 (none for the year ended December 31, 2014).
Acquisition [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. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to income taxes; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method. 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. Fair value measurements were valued primarily using the discounted cash flow method. 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 $3.6 million and construction in process of $23.4 million. There were no liabilities assumed and no recognition of goodwill. 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 during the first quarter of 2015 to certain assets and liabilities, which are reflected in the table below. The result of these adjustments had no impact on the results of operations for the nine months ended September 30, 2015. Fair value measurements were valued primarily using the discounted cash flow method. 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. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to property, plant and equipment, working capital and PPAs; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method. 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 during the third quarter of 2015 to certain assets and liabilities, which are reflected in the table below. The result of these adjustments had no impact on the results of operations for the nine months ended September 30, 2015. Fair value measurements were valued primarily using the discounted cash flow method.
Percentage of Completion Method of Accounting for Contracts [Policy Text Block]	As a result of the NDPSC approval of the sale agreement with Montana-Dakota Utilities in the second quarter of 2015, ALLETE Clean Energy began accounting for the project under the percentage of completion method of accounting for contracts. The percentage of completion used to recognize revenue and cost of sales is calculated based on the percentage of construction costs incurred at the measurement date compared to the estimated total construction costs. We have selected this method because we consider construction costs to be the best available measure of progress on the project. Any adjustments to the estimated percentage of completion or estimated earnings, and the related impacts to operating income, are recorded in the period they become known.
Fair Value Measurement [Policy Text Block]	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Descriptions of the three levels of the fair value hierarchy are discussed in Note 10. Fair Value to the Consolidated Financial Statements in our 2014 Form 10-K. The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015, and December 31, 2014. 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. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to 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 Text Block]	We account for our investment in ATC under the equity method of accounting.
Income Tax [Policy Text Block]	The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate, and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.
Earnings Per Share [Policy Text Block]	We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. 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
Environmental Accruals [Policy Text Block]	We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information 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.

Operations and Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2015

Operations and Significant Accounting Policies [Abstract]

Inventories [Table Text Block]



Inventories	September 30, 2015			December 31, 2014
Millions
Fuel		$54.0			$29.0
Materials and Supplies	52.6			51.5
Raw Materials	3.1			—
Work in Progress	0.7			—
Finished Goods	8.9			—
Reserve for Obsolescence	(0.2		)	—
Total Inventories		$119.1			$80.5

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	September 30, 2015		December 31, 2014
Millions
Deferred Fuel Adjustment Clause		$16.3		$16.3
Construction Costs for Development Project (a)	—		48.2
Restricted Cash (b)	8.1		2.7
Other	18.1		14.8
Total Prepayments and Other Current Assets		$42.5		$82.0


(a)	Construction Costs for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these costs have been net against contract billings. (See Billings in Excess of Costs and Estimated Earnings in Other Current Liabilities table and Note 4. Acquisitions.)


(b)	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities’ operating expense and capital distribution reserve requirements, and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.

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



Other Current Liabilities	September 30, 2015		December 31, 2014
Millions
Customer Deposits		$17.6		$19.7
Power Purchase Agreements (a)	23.8		19.4
Construction Deposits Received for Development Project (b)	—		54.3
Billings in Excess of Costs and Estimated Earnings (c)	8.8		—
Other	44.1		27.4
Total Other Current Liabilities		$94.3		$120.8


(a)	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)


(b)	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these deposits have been net against contract costs and estimated gross profit. (See Billings in Excess of Costs and Estimated Earnings below and Note 4. Acquisitions.)


(c)	Billings in Excess of Costs and Estimated Earnings represents the excess of contract billings over the construction costs incurred and estimated earnings recognized. In the second quarter of 2015, the NDPSC approved the sale agreement ALLETE Clean Energy has with Montana-Dakota Utilities to develop, construct, and sell a wind energy facility in 2015. (See Note 4. Acquisitions.)



Other Non-Current Liabilities	September 30, 2015		December 31, 2014
Millions
Asset Retirement Obligation		$126.3		$109.2
Power Purchase Agreements (a)	143.9		110.7
Contingent Consideration (b)	37.4		—
Other	45.1		45.1
Total Other Non-Current Liabilities		$352.7		$265.0


(a)	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)


(b)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 4. Acquisitions and Note 6. Fair Value.)

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



Nine Months Ended September 30,	2015		2014
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$46.6		$39.4
Cash Paid During the Period for Income Taxes		$0.1		$2.8
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(26.8)		$(6.5)
Capitalized Asset Retirement Costs		$7.8		$0.6
AFUDC–Equity		$2.6		$5.9
ALLETE Common Stock Contributed to the Pension Plan	—			$19.5
Contingent Consideration		$35.7	—

Business Segments (Tables)

9 Months Ended

Sep. 30, 2015

Business Segments [Abstract]

Business Segments [Table Text Block]



	Quarter Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015			2014
Millions
Operating Revenue
Regulated Operations	$250.2		$255.8		$743.0			$749.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	151.1		6.8		197.5			22.6
U.S. Water Services	36.1		—		86.0			—

Corporate and Other	25.1		26.3		79.3			73.9
Total Operating Revenue		$462.5		$288.9		$1,105.8			$846.1
Net Income (Loss) Attributable to ALLETE
Regulated Operations (a)		$43.8		$40.9		$108.1			$91.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	13.2		0.5		18.7			1.2
U.S. Water Services	1.0		—		1.5			—

Corporate and Other (a)	2.4		0.2		(5.5		)	(0.9		)
Total Net Income Attributable to ALLETE		$60.4		$41.6		$122.8			$91.9

(a)



As of September 30,	2015		2014
Millions
Assets
Regulated Operations	$3,836.3		$3,519.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	565.7		184.4
U.S. Water Services	257.8		—

Corporate and Other	272.0		363.6
Total Assets		$4,931.8		$4,067.9

- 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

Investments (Tables)

9 Months Ended

Sep. 30, 2015

Investments [Abstract]

Other Investments [Table Text Block]



Other Investments	September 30, 2015		December 31, 2014
Millions
ALLETE Properties		$88.3		$88.2
Available-for-sale Securities (a)	18.5		18.9
Cash Equivalents	2.6		2.9
Other	4.1		4.4
Total Other Investments		$113.5		$114.4


(a)	As of September 30, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $1.6 million, in three years to less than five years was $3.0 million, and in five or more years was $6.4 million.

Available-for-sale Securities [Table Text Block]



Available-For-Sale Securities
Millions		Gross Unrealized
	Cost	Gain	Loss	Fair Value
September 30, 2015	$20.1	$0.1	$1.7	$18.5
December 31, 2014	$19.6	$0.2	$0.9	$18.9

		Net	Gross Realized
		Proceeds	Gain	Loss
Quarter Ended September 30,
2015		—	—	—
2014		$0.6	—	—
Nine Months Ended September 30,
2015		$0.7	$0.1	—
2014		$3.3	$0.2	—

Acquisitions (Table)

9 Months Ended

Sep. 30, 2015

Acquisitions [Abstract]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$0.9
Accounts Receivable	16.8
Inventories (a)	13.4
Other Current Assets (b)	5.3
Property, Plant and Equipment	10.6
Goodwill (c)	127.7
Intangible Assets (d)	83.0
Other Non-Current Assets	0.2
Total Assets Acquired		$257.9
Liabilities Assumed
Current Liabilities		$19.2
Non-Current Liabilities	36.4
Total Liabilities Assumed		$55.6
Net Identifiable Assets Acquired		$202.3


(a)	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which will be recognized as Cost of Sales within one year from the acquisition date.


(b)	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog will be recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for stand-by letters of credit.


(c)	For tax purposes, the purchase price allocation resulted in $3.2 million of deductible Goodwill.


(d)	Intangible Assets include customer relationships, patents, non-compete agreements and trademarks and trade names. (See Note 5. Goodwill and Intangible Assets.)



Millions
Assets Acquired
Cash and Cash Equivalents		$3.8
Other Current Assets	14.3
Property, Plant and Equipment	156.9
Other Non-Current Assets (a)	7.5
Total Assets Acquired		$182.5
Liabilities Assumed
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, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.


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


(c)	The purchase price accounting valued the non-controlling interest relating to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method.



Millions
Assets Acquired
Current Assets		$4.8
Property, Plant and Equipment	103.0
Other Non-Current Assets (a)	1.0
Total Assets Acquired		$108.8
Liabilities Assumed
Current Liabilities (b)		$6.7
Power Purchase Agreements	49.0
Non-Current Liabilities	5.1
Total Liabilities Assumed		$60.8
Net Identifiable Assets Acquired		$48.0


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


(b)	Current Liabilities included $5.9 million related to the current portion of Power Purchase Agreements.



Millions
Assets Acquired
Current Assets (a)	$9.0
Property, Plant and Equipment	156.7
Other Non-Current Assets (b)	14.4
Total Assets Acquired		$180.1
Liabilities Assumed
Current Liabilities		$3.4
Long-Term Debt Due Within One Year	5.9
Long-Term Debt	55.0
Other Non-Current Liabilities	4.7
Total Liabilities Assumed	$69.0
Net Identifiable Assets Acquired		$111.1


(a)	Included in Current Assets was $1.0 million related to the current portion of Power Purchase Agreements and $6.0 million of restricted cash related to capital distribution reserve requirements.


(b)	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of Power Purchase Agreements, $6.1 million of restricted cash related to operating expense and major maintenance reserve requirements, and $0.1 million of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.



Millions
Assets Acquired
Cash and Cash Equivalents		$0.4
Other Current Assets	4.7
Property, Plant and Equipment	47.3
Other Non-Current Assets (a)	11.4
Total Assets Acquired		$63.8
Liabilities Assumed
Current Liabilities (b)		$8.2
Power Purchase Agreements	23.5
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)	Current Liabilities included $7.5 million related to the current portion of Power Purchase Agreements.

Billings in Excess of Costs and Estimated Earnings [Table Text Block]

The following table summarizes contract billings, construction costs, and estimated earnings recognized for the wind facility:



	September 30, 2015
Millions
Contract Billings	$169.7
Construction Costs	137.5
Estimated Earnings	23.4
Billings in Excess of Costs and Estimated Earnings (a)		$8.8


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

Goodwill and Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2015

Goodwill and Intangible Assets [Abstract]

Schedule of Goodwill [Table Text Block]

The following table summarizes changes to goodwill by business segment for the nine months ended September 30, 2015:



	ALLETE Clean Energy		U.S. Water Services		Total
Millions
Balance as of December 31, 2014		$2.9	—			$2.9
Acquired Goodwill	0.4			$127.7	128.1
Balance as of September 30, 2015		$3.3		$127.7		$131.0

Schedule of Intangible Assets [Table Text Block]

Balances of intangible assets, net, excluding goodwill as of September 30, 2015, are as follows:



	December 31, 2014		Additions (a)		Amortization	Other (b)	September 30, 2015
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	—			$60.1	$(2.2)	—		$57.9
Developed Technology and Other (c)		$1.9	6.4		(0.6)	$(0.3)	7.4
Total Definite-Lived Intangible Assets	1.9		66.5		(2.8)	(0.3)	65.3
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	—		16.6		n/a	—	16.6
Total Intangible Assets		$1.9		$83.1	$(2.8)	$(0.3)		$81.9


(a)	Additions are primarily the result of the U.S. Water Services acquisition. (See Note 4. Acquisitions.)


(b)	Armenia Mountain was acquired on July 1, 2015, at which time the purchase option intangible asset was reclassified as a component of the acquisition consideration.


(c)	Developed Technology and Other includes patents, non-compete agreements, and land easements.

Fair Value (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of September 30, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets:
Investments (a)
Available-for-sale – Equity Securities		$7.3	—		—			$7.3
Available-for-sale – Corporate Debt Securities	—			$11.2	—		11.2
Cash Equivalents	2.6		—		—		2.6
Total Fair Value of Assets		$9.9		$11.2	—			$21.1

Liabilities:
Deferred Compensation (b)	—			$15.9	—			$15.9
Derivatives – Interest Rate Swap (c)	—		4.8		—		4.8
U.S. Water Services Contingent Consideration (b)	—		—			$37.4	37.4
Total Fair Value of Liabilities	—			$20.7		$37.4		$58.1
Total Net Fair Value of Assets (Liabilities)		$9.9	$(9.5)		$(37.4)		$(37.0)


(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.

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



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2014	—
Recognition of U.S. Water Services Contingent Consideration		$35.7
Accretion Expense (a)	1.8
Payments (b)	(0.1		)
Balance as of September 30, 2015		$37.4


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


(b)	Amounts paid to terminated employees.

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Current Portion
September 30, 2015	$1,598.1	$1,685.2
December 31, 2014	$1,373.5	$1,484.5

- 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

- Definition

Tabular disclosure of the fair value measurement of liabilities using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and gains or losses recognized in other comprehensive income (loss) and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs) by class of liability.

+ References+ Details

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2015

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	September 30, 2015		December 31, 2014
Millions
Current Regulatory Assets (a)
Deferred Fuel		$16.3		$16.3
Total Current Regulatory Assets	16.3		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	212.3		223.9
Cost Recovery Riders (c)	64.0		59.7
Income Taxes	46.9		46.6
Asset Retirement Obligations	20.5		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	4.6		4.3
Total Non-Current Regulatory Assets	353.3		357.3
Total Regulatory Assets		$369.6		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$54.5		$42.9
Plant Removal Obligations	20.9		22.8
Income Taxes	12.8		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	1.8		3.5
Other	15.8		11.6
Total Non-Current Regulatory Liabilities		$105.8		$94.2


(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 14. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are primarily due to capital expenditures related to the 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)

9 Months Ended

Sep. 30, 2015

Investment in ATC [Abstract]

ALLETE's Investment in ATC [Table Text Block]



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2014		$121.1
Cash Investments	1.2
Equity in ATC Earnings	14.1
Distributed ATC Earnings	(10.4		)
Equity Investment Balance as of September 30, 2015		$126.0

NOTE 8. INVESTMENT IN ATC (Continued)

ATC’s summarized financial data for the quarter and nine months ended September 30, 2015 and 2014, is as follows:



	Quarter Ended				Nine Months Ended
ATC Summarized Financial Data	September 30,				September 30,
Income Statement Data	2015		2014		2015		2014
Millions
Revenue		$164.5		$163.6		$482.0		$487.0
Operating Expense	78.0		76.6		238.3		229.6
Other Expense	23.1		21.4		71.7		65.1
Net Income		$63.4		$65.6		$172.0		$192.3
ALLETE’s Equity in Net Income		$5.5		$5.3		$14.1		$15.6

Short-Term and Long-Term Debt Short-Term and Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2015

Short-Term and Long-Term Debt [Abstract]

Expected First Mortgage Bonds Issuance [Table Text Block]

On September 24, 2015, we issued $100.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:



Maturity Date	Principal Amount	Interest Rate
September 15, 2020	$40 Million	2.80%
September 16, 2030	$60 Million	3.86%

- 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 835

-SubTopic 30

-Section 55

-Paragraph 8

-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

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-Topic 835

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-Topic 835

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-Name Accounting Standards Codification

-Topic 505

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 210

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.5-02.22)

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-Name Accounting Standards Codification

-Topic 942

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-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

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

-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Income Tax Expense (Tables)

9 Months Ended

Sep. 30, 2015

Income Tax Expense [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended					Nine Months Ended
	September 30,					September 30,
	2015		2014			2015			2014
Millions
Current Tax Expense
Federal (a)	—		—			—			—
State (a) (b)	$0.2		$1.8				$0.5		$1.9
Total Current Tax Expense	$0.2		$1.8				$0.5		$1.9
Deferred Tax Expense (Benefit)
Federal	$14.8			$11.2		$23.5				$20.4
State	(0.4	)	0.7			3.6			5.4
Investment Tax Credit Amortization	(0.2	)	(0.3		)	(0.6		)	(0.6		)
Total Deferred Tax Expense	14.2		11.6			26.5			25.2
Total Income Tax Expense	$14.4			$13.4		$27.0				$27.1


(a)	For the quarter and nine months ended September 30, 2015, the federal and state current tax expense was minimal due to the utilization of NOL carryforwards from prior periods. The NOL carryforwards resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.


(b)	For the quarter and nine months ended September 30, 2014, the state current tax expense reflected initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired due to NOL carryforwards from prior periods. State NOL and alternative minimum tax carryforwards remaining after utilization in 2015 will be carried forward to offset future income.

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
Nine Months Ended September 30	2015			2014
Millions
Income Before Non-Controlling Interest and Income Taxes		$149.7			$119.4
Statutory Federal Income Tax Rate	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate	52.4			41.8
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	2.6			4.8
Production Tax Credits	(27.0		)	(16.4		)
Regulatory Differences for Utility Plant	(0.7		)	(2.1		)
Other	(0.3		)	(1.0		)
Total Income Tax Expense		$27.0			$27.1

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

9 Months Ended

Sep. 30, 2015

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

Changes in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Changes in accumulated other comprehensive income (loss), net of tax, for the nine months ended September 30, 2015 and 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
Nine Months Ended September 30, 2015
Beginning Accumulated Other Comprehensive Loss	$(0.3)		$(20.7)		$(0.1)	$(21.1)
Other Comprehensive Income (Loss) Before Reclassifications	(0.5)		0.1		0.1	(0.3	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1)		0.9		—	0.8
Net Other Comprehensive Income (Loss)	(0.6)		1.0		0.1	0.5
Ending Accumulated Other Comprehensive Loss	$(0.9)		$(19.7)		—	$(20.6)

Nine Months Ended September 30, 2014
Beginning Accumulated Other Comprehensive Loss	$(0.1)		$(16.7)		$(0.3)	$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications	0.2		(0.1	)	0.1	0.2
Amounts Reclassified From Accumulated Other Comprehensive Loss	(0.1	)	0.9		—	0.8
Net Other Comprehensive Income	0.1		0.8		0.1	1.0
Ending Accumulated Other Comprehensive Loss	—		$(15.9)		$(0.2)	$(16.1)

Changes in accumulated other comprehensive income (loss), net of tax, for the quarters ended September 30, 2015 and 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
Quarter Ended September 30, 2015
Beginning Accumulated Other Comprehensive Loss	$(0.2)		$(20.0)		—	$(20.2)
Other Comprehensive Loss Before Reclassifications	(0.7)		—		—	(0.7	)
Amounts Reclassified From Accumulated Other Comprehensive Loss	—		0.3		—	0.3
Net Other Comprehensive Income (Loss)	(0.7)		0.3		—	(0.4	)
Ending Accumulated Other Comprehensive Loss	$(0.9)		$(19.7)		—	$(20.6)

Quarter Ended September 30, 2014
Beginning Accumulated Other Comprehensive Income (Loss)	$0.1		$(16.1)		$(0.3)	$(16.3)
Other Comprehensive Income (Loss) Before Reclassifications	(0.1	)	(0.1	)	0.1	(0.1	)
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)	—		0.3		—	0.3
Net Other Comprehensive Income (Loss)	(0.1	)	0.2		0.1	0.2
Ending Accumulated Other Comprehensive Loss	—		$(15.9)		$(0.2)	$(16.1)

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

Reclassifications from accumulated other comprehensive income (loss) for the nine months ended September 30, 2015 and 2014, were as follows:



	Nine Months Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	September 30,			September 30,
	2015			2014
Millions
Unrealized Gains on Available-for-sale Securities (a)		$0.1			$0.2
Income Taxes (b)	—			(0.1		)
Total, Net of Income Taxes		$0.1			$0.1

Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (c)	$0.3			$0.3
Actuarial Gains and Losses (c)	(1.9		)	(1.8		)
Total	(1.6		)	(1.5		)
Income Taxes (b)	0.7			0.6
Total, Net of Income Taxes	$(0.9)			$(0.9)
Total Reclassifications	$(0.8)			$(0.8)


(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 14. Pension and Other Postretirement Benefit Plans.)

Reclassifications from accumulated other comprehensive income (loss) for the quarters ended September 30, 2015 and 2014, were as follows:



	Quarter Ended
Amount Reclassified from Accumulated Other Comprehensive Loss	September 30,		September 30,
	2015		2014
Millions
Amortization of Defined Benefit Pension and Other Postretirement Items
Prior Service Costs (a)	$0.1		$0.1
Actuarial Gains and Losses (a)	(0.6)		(0.6	)
Total	(0.5	)	(0.5	)
Income Taxes (b)	0.2		0.2
Total, Net of Income Taxes	$(0.3)		$(0.3)
Total Reclassifications	$(0.3)		$(0.3)


(a)	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 14. Pension and Other Postretirement Benefit Plans.)


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

Earnings Per Share and Common Stock (Tables)

9 Months Ended

Sep. 30, 2015

Earnings Per Share and Common Stock [Abstract]

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



			2015					2014
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Quarter ended September 30,
Net Income Attributable to ALLETE		$60.4			$60.4		$41.6			$41.6
Average Common Shares	48.8		0.1	48.9		42.9		—	42.9
Earnings Per Share		$1.24			$1.23		$0.97			$0.97
Nine months ended September 30,
Net Income Attributable to ALLETE		$122.8			$122.8		$91.9			$91.9
Average Common Shares	48.0		0.1	48.1		42.1		0.2	42.3
Earnings Per Share		$2.56			$2.55		$2.18			$2.17

Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2015

Pension and Other Postretirement Benefit Plans [Abstract]

Components of Net Periodic Benefit Expense (Income) [Table Text Block]



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2015			2014			2015		2014
Millions
Quarter Ended September 30,
Service Cost	$2.6				$2.0		$1.0			$0.9
Interest Cost	7.5			7.5			1.8		1.8
Expected Return on Plan Assets	(10.2		)	(9.6		)	(2.7	)	(2.5		)
Amortization of Prior Service Costs (Credits)	—			0.1			(0.7	)	(0.7		)
Amortization of Net Loss	4.4			3.6			0.1		0.1
Net Periodic Benefit Expense (Income)		$4.3			$3.6		$(0.5)		$(0.4)

Nine Months Ended September 30,
Service Cost	$7.6				$6.2		$3.2			$2.6
Interest Cost	22.4			22.4			5.4		5.5
Expected Return on Plan Assets	(30.5		)	(28.7		)	(8.2	)	(7.7		)
Amortization of Prior Service Costs (Credits)	0.1			0.2			(2.2	)	(1.9		)
Amortization of Net Loss	13.4			10.7			0.3		0.3
Net Periodic Benefit Expense (Income)		$13.0			$10.8		$(1.5)		$(1.2)

Operations and Significant Accounting Policies - Reclassifications (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014 Operating and Maintenance Expenses to Cost of Sales [Member]	Sep. 30, 2014 Operating and Maintenance Expenses to Cost of Sales [Member]	Sep. 30, 2014 Operating and Maintenance Expenses to Transmission Services [Member]	Sep. 30, 2014 Operating and Maintenance Expenses to Transmission Services [Member]	Sep. 30, 2014 Operating and Maintenance Expenses to Taxes Other than Income Taxes [Member]	Sep. 30, 2014 Operating and Maintenance Expenses to Taxes Other than Income Taxes [Member]	Sep. 30, 2014 Operating Income [Member]	Sep. 30, 2014 Operating Income [Member]	Sep. 30, 2014 Net Income [Member]	Sep. 30, 2014 Net Income [Member]	Sep. 30, 2014 Net Income Attributable to ALLETE [Member]	Sep. 30, 2014 Net Income Attributable to ALLETE [Member]	Dec. 31, 2014 Property, Plant and Equipment - Net to Goodwill and Intangible Assets - Net [Member]	Dec. 31, 2014 Other Non-Current Assets to Goodwill and Intangible Assets - Net [Member]	Dec. 31, 2014 Total Assets [Member]
Reclassifications [Line Items]
Reclassification Adjustment	$ 16.8	$ 59.2	$ 11.9	$ 33.2	$ 11.4	$ 33.9	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 1.6	$ 3.2	$ 0

Operations and Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified

9 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Sep. 30, 2015

Debt Service and Other Requirements [Member]

Dec. 31, 2014

Debt Service and Other Requirements [Member]

Sep. 30, 2015

Minimum [Member]

Sep. 30, 2015

Maximum [Member]

Inventories [Abstract]

Fuel

$ 54.0

$ 29.0

Materials and Supplies

52.6

51.5

Raw Materials

3.1

Work in Progress

0.7

Finished Goods

8.9

Reserve for Obsolescence

(0.2)

Total Inventories

119.1

80.5

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

16.3

Construction Costs for Development Project

^[1]

48.2

^[1]

Restricted Cash

8.1

^[2]

2.7

^[2]

Other

18.1

14.8

Total Prepayments and Other Current Assets

42.5

82.0

Finite-Lived Intangible Assets [Line Items]

Definite-Lived Intangible Assets, Useful Life (Years)

3 years

22 years

Statement [Line Items]

Restricted Cash, Noncurrent

11.9

5.3

Other Current Liabilites [Abstract]

Customer Deposits

17.6

19.7

Power Purchase Agreements

23.8

^[3]

19.4

^[3]

Construction Deposits Received for Development Project

^[4]

54.3

^[4]

Billings in Excess of Costs and Estimated Earnings

8.8

^[5]

Other

44.1

27.4

Total Other Current Liabilities

94.3

120.8

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

126.3

109.2

Power Purchase Agreements

143.9

^[3]

110.7

^[3]

Contingent Consideration

37.4

^[6]

Other

45.1

Total Other Non-Current Liabilities

$ 352.7

$ 265.0

[1]	Construction Costs for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these costs have been net against contract billings. (See Billings in Excess of Costs and Estimated Earnings in Other Current Liabilities table and Note 4. Acquisitions.)
[2]	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities’ operating expense and capital distribution reserve requirements, and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.
[3]	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)
[4]	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these deposits have been net against contract costs and estimated gross profit. (See Billings in Excess of Costs and Estimated Earnings below and Note 4. Acquisitions.)
[5]	Billings in Excess of Costs and Estimated Earnings represents the excess of contract billings over the construction costs incurred and estimated earnings recognized. In the second quarter of 2015, the NDPSC approved the sale agreement ALLETE Clean Energy has with Montana-Dakota Utilities to develop, construct, and sell a wind energy facility in 2015. (See Note 4. Acquisitions.)
[6]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 4. Acquisitions and Note 6. Fair Value.)

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Supplemental Cash Flow Elements [Abstract]
Cash Paid During the Period for Interest - Net of Amounts Capitalized	$ 46.6	$ 39.4
Cash Paid During the Period for Income Taxes	0.1	2.8
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	(26.8)	(6.5)
Capitalized Asset Retirement Costs	7.8	0.6
AFUDC–Equity	2.6	5.9
ALLETE Common Stock Contributed to the Pension Plan	0	19.5
Contingent Consideration	$ 35.7	$ 0

Business Segments (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Business Segments [Line Items]

Description of Effect on Previously Reported Segment Information for Change in Composition of Reportable Segments

Number of Reportable Segments

Operating Revenue

$ 462.5

$ 288.9

$ 1,105.8

$ 846.1

Net Income (Loss) Attributable to ALLETE

60.4

41.6

122.8

91.9

Equity Method Investment, Ownership Percentage

8.00%

Interest Expense

17.7

13.2

49.0

39.5

Total Assets

4,931.8

4,067.9

4,931.8

4,067.9

4,360.8

Regulated Operations [Member] [Member]

Business Segments [Line Items]

Number of Operating Segments

Operating Revenue

250.2

255.8

743.0

749.6

Net Income (Loss) Attributable to ALLETE

43.8

^[1]

40.9

^[1]

108.1

^[1]

91.6

^[1]

Equity Method Investment, Ownership Percentage

8.00%

Total Assets

3,836.3

3,519.9

3,836.3

3,519.9

ALLETE Clean Energy [Member]

Business Segments [Line Items]

Operating Revenue

151.1

6.8

197.5

22.6

Net Income (Loss) Attributable to ALLETE

13.2

0.5

18.7

1.2

Total Assets

565.7

184.4

565.7

184.4

U.S. Water Services [Member]

Business Segments [Line Items]

Operating Revenue

36.1

86.0

Net Income (Loss) Attributable to ALLETE

1.0

1.5

Total Assets

257.8

Corporate and Other [Member]

Business Segments [Line Items]

Number of Operating Segments

Land in Minnesota (in acres)

5,000

Operating Revenue

25.1

26.3

79.3

73.9

Net Income (Loss) Attributable to ALLETE

2.4

^[1]

0.2

^[1]

(5.5)

^[1]

(0.9)

^[1]

Total Assets

272.0

363.6

272.0

363.6

Related Party [Member] | Regulated Operations [Member] [Member]

Business Segments [Line Items]

Interest Expense

0.3

Related Party [Member] | Corporate and Other [Member]

Business Segments [Line Items]

Interest Income

$ 1.8

[1]

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

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Investments [Abstract]

ALLETE Properties

$ 88.3

$ 88.2

Available-for-sale Securities

18.5

^[1]

18.5

^[1]

18.9

Cash Equivalents

2.6

2.9

Other

4.1

4.4

Total Other Investments

113.5

114.4

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

0.2

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

1.6

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

3.0

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

6.4

Impairment of Land Inventory

$ 0

[1]	As of September 30, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $1.6 million, in three years to less than five years was $3.0 million, and in five or more years was $6.4 million.

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

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Available-for-sale Securities [Abstract]

Cost

$ 20.1

$ 19.6

Gross Unrealized Gain

0.1

0.2

Gross Unrealized Loss

1.7

0.9

Fair Value

18.5

^[1]

18.5

^[1]

18.9

Net Proceeds

0.6

0.7

3.3

Gross Realized Gain

0.1

0.2

Gross Realized Loss

$ 0

[1]	As of September 30, 2015, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $1.6 million, in three years to less than five years was $3.0 million, and in five or more years was $6.4 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

Acquisitions (Details)	9 Months Ended	12 Months Ended
Acquisitions (Details)	Sep. 30, 2015	Dec. 31, 2014
Acquisitions [Abstract]
Reason for Business Acquisitions	The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.	The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.
Pro Forma Impact of Business Acquisitions	not significant	not significant

Acquisitions - U.S. Water Services (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Feb. 10, 2015

U.S. Water Services [Member]

Mar. 31, 2015

U.S. Water Services [Member]

Sep. 30, 2015

U.S. Water Services [Member]

Feb. 10, 2015

U.S. Water Services [Member]

Business Acquisition [Line Items]

Date of Acquisition

Feb. 10, 2015

Name of Acquired Entity

U.S. Water Services

Consideration Transferred

$ 202.3

Payments to Acquire Business

166.6

Contingent Consideration

35.7

Percent of Results of Operations Reflected in Income Statement

100.00%

Percentage of Voting Interests Acquired

100.00%

Assets [Abstract]

Cash and Cash Equivalents

0.9

Accounts Receivable

16.8

Inventories

13.4

^[1]

Other Current Assets

5.3

^[2]

Property, Plant and Equipment

10.6

Goodwill

131.0

2.9

127.7

^[3]

Intangible Assets

83.0

^[4]

Other Non-Current Assets

0.2

Total Assets Acquired

257.9

Liabilities [Abstract]

Current Liabilities

19.2

Non-Current Liabilities

36.4

Total Liabilities Assumed

55.6

Net Identifiable Assets Acquired

202.3

Fair Value Adjustments for Work in Process and Finished Goods

2.7

Fair Value of Sales Backlog

1.6

Restricted Cash, Current

8.1

^[5]

2.7

^[5]

2.1

Expected Tax Deductible Amount of Goodwill

3.2

Acquisition Related Costs

$ 3.0

[1]	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which will be recognized as Cost of Sales within one year from the acquisition date.
[2]	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog will be recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for stand-by letters of credit.
[3]	For tax purposes, the purchase price allocation resulted in $3.2 million of deductible Goodwill.
[4]	Intangible Assets include customer relationships, patents, non-compete agreements and trademarks and trade names. (See Note 5. Goodwill and Intangible Assets.)
[5]	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities’ operating expense and capital distribution reserve requirements, and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.

Acquisitions - Chanarambie/Viking (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

6 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Apr. 15, 2015

Chanarambie/Viking [Member]

Jun. 30, 2015

Chanarambie/Viking [Member]

Apr. 15, 2015

Chanarambie/Viking [Member]

Apr. 15, 2015

Chanarambie/Viking [Member]

Chanarambie/Viking PPA (expires 2018) [Member]

Apr. 15, 2015

Chanarambie/Viking [Member]

Chanarambie/Viking PPA (expires 2023) [Member]

Business Acquisition [Line Items]

Date of Acquisition

Apr. 15, 2015

Name of Acquired Entity

Chanarambie/Viking

Payments to Acquire Business

$ 48.0

Generating Capacity (MW)

97.5

85.5

Assets [Abstract]

Current Assets

4.8

Property, Plant and Equipment

103.0

Other Non-Current Assets

1.0

^[1]

Total Assets Acquired

108.8

Liabilities [Abstract]

Current Liabilities

6.7

^[2]

Power Purchase Agreements, Non-Current Liability

143.9

^[3]

110.7

^[3]

49.0

Non-Current Liabilities

5.1

Total Liabilities Assumed

60.8

Net Identifiable Assets Acquired

48.0

Goodwill

131.0

2.9

0.3

Expected Tax Deductible Amount of Goodwill

Power Purchase Agreements, Current Liability

23.8

^[3]

19.4

^[3]

5.9

Acquisition Related Costs

$ 0.2

[1]	Included in Other Non-Current Assets was $0.3 million of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[2]	Current Liabilities included $5.9 million related to the current portion of Power Purchase Agreements.
[3]	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)

Acquisitions - Armenia Mountain (Details) (USD $)
In Millions, unless otherwise specified

0 Months Ended

9 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Jul. 01, 2015

Armenia Mountain [Member]

Sep. 30, 2015

Armenia Mountain [Member]

Jul. 01, 2015

Armenia Mountain [Member]

Business Acquisition [Line Items]

Date of Acquisition

Jul. 01, 2015

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Armenia Mountain

Payments to Acquire Business

$ 111.1

Generating Capacity (MW)

100.5

Assets [Abstract]

Current Assets

9.0

^[1]

Property, Plant and Equipment

156.7

Other Non-Current Assets

14.4

^[2]

Total Assets Acquired

180.1

Liabilities [Abstract]

Current Liabilities

3.4

Long-term Debt Due Within One Year

5.9

Long-term Debt

55.0

Other Non-Current Liabilities

4.7

Total Liabilities Assumed

69.0

Net Identifiable Assets Acquired

111.1

Power Purchase Agreements, Current Asset

1.0

Restricted Cash, Current

8.1

^[3]

2.7

^[3]

6.0

Power Purchase Agreements, Non-Current Asset

8.2

Restricted Cash, Non-Current

6.1

Goodwill

131.0

2.9

0.1

Expected Tax Deductible Amount of Goodwill

Acquisition Related Costs

$ 1.6

[1]	Included in Current Assets was $1.0 million related to the current portion of Power Purchase Agreements and $6.0 million of restricted cash related to capital distribution reserve requirements.
[2]	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of Power Purchase Agreements, $6.1 million of restricted cash related to operating expense and major maintenance reserve requirements, and $0.1 million of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
[3]	Restricted Cash related to ALLETE Clean Energy’s wind energy facilities’ operating expense and capital distribution reserve requirements, and cash pledged as collateral by U.S. Water Services for stand-by letters of credit.

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

0 Months Ended

9 Months Ended

Nov. 20, 2014

Sep. 30, 2015

Dec. 31, 2014

Nov. 20, 2014

Assets [Abstract]

Construction Costs

$ 0

^[1]

$ 48.2

^[1]

Goodwill

131.0

2.9

Billings in Excess of Costs and Estimated Earnings [Abstract]

Contract Billings

^[2]

54.3

^[2]

Construction Costs

^[1]

48.2

^[1]

Billings in Excess of Costs and Estimated Earnings

8.8

^[3]

Wind Development Project [Member]

Business Acquisition [Line Items]

Date of Acquisition

Nov. 20, 2014

Payments to Acquire Business

27.0

Generating Capacity (MW)

107.0

Number of Wind Turbines

Contractual Sales Price

200

Assets [Abstract]

Cash and Cash Equivalents

3.6

Construction Costs

137.5

48.2

23.4

Goodwill

Liabilities [Abstract]

Total Liabilities Assumed

Billings in Excess of Costs and Estimated Earnings [Abstract]

Contract Billings

169.7

54.3

Construction Costs

137.5

48.2

23.4

Estimated Earnings

23.4

Billings in Excess of Costs and Estimated Earnings

8.8

^[4]

Revenue

156.4

Cost of Sales

$ 133.0

[1]	Construction Costs for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these costs have been net against contract billings. (See Billings in Excess of Costs and Estimated Earnings in Other Current Liabilities table and Note 4. Acquisitions.)
[2]	Construction Deposits Received for Development Project relate to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. Beginning in the second quarter of 2015, these deposits have been net against contract costs and estimated gross profit. (See Billings in Excess of Costs and Estimated Earnings below and Note 4. Acquisitions.)
[3]	Billings in Excess of Costs and Estimated Earnings represents the excess of contract billings over the construction costs incurred and estimated earnings recognized. In the second quarter of 2015, the NDPSC approved the sale agreement ALLETE Clean Energy has with Montana-Dakota Utilities to develop, construct, and sell a wind energy facility in 2015. (See Note 4. Acquisitions.)
[4]	Included in Current Liabilities - Other on the Consolidated Balance Sheet.

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

0 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Jan. 30, 2014

Armenia Mountain [Member]

Feb. 11, 2014

ACE Wind [Member]

Jan. 30, 2014

ACE Wind [Member]

Jan. 30, 2014

ACE Wind [Member]

Jan. 30, 2014

Lake Benton [Member]

Jan. 30, 2014

Lake Benton [Member]

Jan. 30, 2014

Storm Lake II [Member]

Jan. 30, 2014

Storm Lake II [Member]

Jan. 30, 2014

Condon [Member]

Jan. 30, 2014

Condon [Member]

Business Acquisition [Line Items]

Date of Acquisition

Jan. 30, 2014

Name of Acquired Entity

Lake Benton

Storm Lake II

Condon

Payments to Acquire Business

$ 26.9

Generating Capacity (MW)

104.0

Number of Wind Energy Facilities Acquired

Assets [Abstract]

Cash and Cash Equivalents

3.8

Other Current Assets

14.3

Property, Plant and Equipment

156.9

Other Non-Current Assets

7.5

^[1]

Total Assets Acquired

182.5

Liabilities [Abstract]

Current Liabilities

15.2

^[2]

Long-term Debt Due Within One Year

2.2

Long-term Debt

21.1

Power Purchase Agreements, Non-Current Liability

143.9

^[3]

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

131.0

2.9

Expected Tax Deductible Amount of Goodwill

Power Purchase Agreements, Current Liability

23.8

^[3]

19.4

^[3]

12.4

Non-Controlling Interest, Decrease from Purchase of Interests

$ 6.0

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

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

0 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Dec. 17, 2014

Storm Lake I [Member]

Dec. 17, 2014

Storm Lake I [Member]

Business Acquisition [Line Items]

Date of Acquisition

Dec. 17, 2014

Name of Acquired Entity

Storm Lake I

Payments to Acquire Business

$ 15.1

Generating Capacity (MW)

108.0

Assets [Abstract]

Cash and Cash Equivalents

0.4

Other Current Assets

4.7

Property, Plant and Equipment

47.3

Other Non-Current Assets

11.4

^[1]

Total Assets Acquired

63.8

Liabilities [Abstract]

Current Liabilities

8.2

^[2]

Power Purchase Agreements, Non-Current Liability

143.9

^[3]

110.7

^[3]

23.5

Non-Current Liabilities

17.0

Total Liabilities Assumed

48.7

Net Identifiable Assets Acquired

15.1

Restricted Cash, Non-Current

0.4

Goodwill

immaterial

Expected Tax Deductible Amount of Goodwill

Power Purchase Agreements, Current Liability

$ 23.8

^[3]

$ 19.4

^[3]

$ 7.5

[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]	Current Liabilities included $7.5 million related to the current portion of Power Purchase Agreements.
[3]	Power Purchase Agreements were acquired in conjunction with ALLETE Clean Energy’s wind energy facilities acquisitions. (See Note 4. Acquisitions.)

Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified

9 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Goodwill [Roll Forward]

Balance as of December 31, 2014

$ 2.9

Acquired Goodwill

128.1

Balance as of September 30, 2015

131.0

Intangible Assets [Abstract]

Definite-Lived Intangible Assets

65.3

1.9

Definite-Lived Intangible Assets, Additions

66.5

^[1]

Definite-Lived Intangible Assets, Amortization

(2.8)

Definite-Lived Intangible Assets, Other

(0.3)

^[2]

Total Intangible Assets

81.9

1.9

Total Intangible Assets, Additions

83.1

^[1]

Total Intangible Assets, Other

(0.3)

^[2]

Definite-Lived Intangible Assets, Accumulated Amortization

2.9

0.1

Definite-Lived Intangible Assets, Estimated Annual Amortization Expense [Abstract]

Definite-Lived Intangible Assets, Estimated Amortization Expense, Remainder of 2015

1.1

Definite-Lived Intangible Assets, Estimated Amortization Expense, 2016

4.3

Definite-Lived Intangible Assets, Estimated Amortization Expense, 2017

4.2

Definite-Lived Intangible Assets, Estimated Amortization Expense, 2018

4.1

Definite-Lived Intangible Assets, Estimated Amortization Expense, 2019

4.0

Definite-Lived Intangible Assets, Estimated Amortization Expense, Thereafter

47.6

Minimum [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets, Useful Life (Years)

3 years

Maximum [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets, Useful Life (Years)

22 years

Weighted Average [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets, Useful Life (Years)

21 years

Trademarks and Trade Names [Member]

Intangible Assets [Abstract]

Indefinite-Lived Intangible Assets

16.6

Indefinite-Lived Intangible Assets, Additions

16.6

^[1]

Indefinite-Lived Intangible Assets, Other

^[2]

Customer Relationships [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets

57.9

Definite-Lived Intangible Assets, Additions

60.1

^[1]

Definite-Lived Intangible Assets, Amortization

(2.2)

Definite-Lived Intangible Assets, Other

^[2]

Definite-Lived Intangible Assets, Useful Life (Years)

22 years

Developed Technology and Other [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets

7.4

^[3]

1.9

^[3]

Definite-Lived Intangible Assets, Additions

6.4

^[1],[3]

Definite-Lived Intangible Assets, Amortization

(0.6)

^[3]

Definite-Lived Intangible Assets, Other

(0.3)

^[2],[3]

Developed Technology and Other [Member] | Minimum [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets, Useful Life (Years)

3 years

Developed Technology and Other [Member] | Maximum [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets, Useful Life (Years)

13 years

Developed Technology and Other [Member] | Weighted Average [Member]

Intangible Assets [Abstract]

Definite-Lived Intangible Assets, Useful Life (Years)

9 years

ALLETE Clean Energy [Member]

Goodwill [Roll Forward]

Balance as of December 31, 2014

2.9

Acquired Goodwill

0.4

Balance as of September 30, 2015

3.3

U.S. Water Services [Member]

Goodwill [Roll Forward]

Balance as of December 31, 2014

Acquired Goodwill

127.7

Balance as of September 30, 2015

$ 127.7

[1]	Additions are primarily the result of the U.S. Water Services acquisition. (See Note 4. Acquisitions.)
[2]	Armenia Mountain was acquired on July 1, 2015, at which time the purchase option intangible asset was reclassified as a component of the acquisition consideration.
[3]	Developed Technology and Other includes patents, non-compete agreements, and land easements.

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

9 Months Ended

12 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Investments [Abstract]

Cash Equivalents

$ 2.6

$ 2.9

Recurring Fair Value Measurements [Member]

Investments [Abstract]

Available-for-sale - Equity Securities

7.3

^[1]

8.1

^[1]

Available-for-sale - Corporate Debt Securities

11.2

^[1]

10.8

^[1]

Cash Equivalents

2.6

^[1]

2.9

^[1]

Total Fair Value of Assets

21.1

21.8

Liabilities [Abstract]

Deferred Compensation

15.9

^[2]

16.2

^[2]

Derivatives - Interest Rate Swap 2015

4.8

^[3]

Derivatives - Interest Rate Swap 2014

0.3

^[4]

U.S. Water Services Contingent Consideration

37.4

^[2]

Total Fair Value of Liabilities

58.1

16.5

Total Net Fair Value of Assets (Liabilities)

(37.0)

5.3

Activity in Level 3 [Roll Forward]

Balance as of September 30, 2015

37.4

^[2]

Fair Value Hierarchy Transfers, All Levels

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

Investments [Abstract]

Available-for-sale - Equity Securities

7.3

^[1]

8.1

^[1]

Available-for-sale - Corporate Debt Securities

^[1]

Cash Equivalents

2.6

^[1]

2.9

^[1]

Total Fair Value of Assets

9.9

11.0

Liabilities [Abstract]

Deferred Compensation

^[2]

Derivatives - Interest Rate Swap 2015

^[3]

Derivatives - Interest Rate Swap 2014

^[4]

U.S. Water Services Contingent Consideration

^[2]

Total Fair Value of Liabilities

Total Net Fair Value of Assets (Liabilities)

9.9

11.0

Activity in Level 3 [Roll Forward]

Balance as of September 30, 2015

^[2]

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

Investments [Abstract]

Available-for-sale - Equity Securities

^[1]

Available-for-sale - Corporate Debt Securities

11.2

^[1]

10.8

^[1]

Cash Equivalents

^[1]

Total Fair Value of Assets

11.2

10.8

Liabilities [Abstract]

Deferred Compensation

15.9

^[2]

16.2

^[2]

Derivatives - Interest Rate Swap 2015

4.8

^[3]

Derivatives - Interest Rate Swap 2014

0.3

^[4]

U.S. Water Services Contingent Consideration

^[2]

Total Fair Value of Liabilities

20.7

16.5

Total Net Fair Value of Assets (Liabilities)

(9.5)

(5.7)

Activity in Level 3 [Roll Forward]

Balance as of September 30, 2015

^[2]

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

Investments [Abstract]

Available-for-sale - Equity Securities

^[1]

Available-for-sale - Corporate Debt Securities

^[1]

Cash Equivalents

^[1]

Total Fair Value of Assets

Liabilities [Abstract]

Deferred Compensation

^[2]

Derivatives - Interest Rate Swap 2015

^[3]

Derivatives - Interest Rate Swap 2014

^[4]

U.S. Water Services Contingent Consideration

37.4

^[2]

Total Fair Value of Liabilities

37.4

Total Net Fair Value of Assets (Liabilities)

(37.4)

Activity in Level 3 [Roll Forward]

Activity in Level 3, Period Increase (Decrease)

Balance as of September 30, 2015

37.4

^[2]

Recurring Fair Value Measurements [Member] | Level 3 [Member] | Recognition of U.S. Water Services Contingent Consideration [Member]

Activity in Level 3 [Roll Forward]

Activity in Level 3, Period Increase (Decrease)

35.7

Recurring Fair Value Measurements [Member] | Level 3 [Member] | Accretion Expense [Member]

Activity in Level 3 [Roll Forward]

Activity in Level 3, Period Increase (Decrease)

1.8

^[5]

Recurring Fair Value Measurements [Member] | Level 3 [Member] | Payments [Member]

Activity in Level 3 [Roll Forward]

Activity in Level 3, Period Increase (Decrease)

$ (0.1)

^[6]

[1]	Included in Other Investments on the Consolidated Balance Sheet.
[2]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[3]	Included in Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.
[4]	Included in Current Liabilities - Other on the Consolidated Balance Sheet.
[5]	Included in Interest Expense on the Consolidated Statement of Income.
[6]	Amounts paid to terminated employees.

Fair Value - Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2015	Dec. 31, 2014
Financial Instruments [Abstract]
Long-Term Debt, Including Current Portion - Carrying Amount	$ 1,598.1	$ 1,373.5
Long-Term Debt, Including Current Portion - Fair Value	$ 1,685.2	$ 1,484.5

Fair Value - Nonrecurring Fair Value Measures (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Nonrecurring Fair Value Measures [Abstract]
Equity Method Investment, Ownership Percentage	8.00%
Equity Method Investment, Carrying Amount	$ 126.0	$ 121.1
Goodwill, Carrying Amount	131.0	2.9
Intangible Assets, Carrying Amount	81.9	1.9
Nonrecurring Fair Value Measurements [Member]
Nonrecurring Fair Value Measures [Abstract]
Equity Method Investment, Ownership Percentage	8.00%
Equity Method Investment, Carrying Amount	126.0	121.1
Equity Method Investment, Impairment	0	0
Goodwill, Carrying Amount	131.0	2.9
Goodwill, Impairment	0
Intangible Assets, Carrying Amount	81.9	1.9
Intangible Assets, Impairment	0
Property, Plant and Equipment, Impairment	$ 0	$ 0

- Definition

The aggregate amount of write-downs for impairments recognized during the period for long lived assets held for use (including those held for disposal by means other than sale).

+ References+ Details

Regulatory Matters - Utility Rates (Details)		0 Months Ended						0 Months Ended
Regulatory Matters - Utility Rates (Details)	Sep. 30, 2015 Bison Wind Energy Center [Member] MW	Jun. 01, 2011 MPUC 2010 Minnesota Rate Case [Member] Electric Rates [Member] Retail Customers [Member]	Jun. 01, 2011 MPUC 2010 Minnesota Rate Case [Member] Electric Rates [Member] Municipal Customers [Member]	Sep. 30, 2015 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Years Customers	Sep. 30, 2015 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Wholesale Electric Contracts (Expire December 2024) [Member] Customers	Sep. 30, 2015 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Minimum [Member] Wholesale Electric Contracts (Expire December 2024) [Member]	Sep. 30, 2015 FERC-Approved Wholesale Rates [Member] Electric Rates [Member] Municipal Customers [Member] Maximum [Member] Wholesale Electric Contracts (Expire December 2024) [Member]	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%	10.38%					10.90%
Approved Percentage of Capital Structure Related to Equity		54.29%
Number of Customers				16	14
Annual Change in Capacity Charge, Percent						(1.00%)	2.00%
Length of Notice Required to Terminate (Years)				3
Generating Capacity (MW)	497

Regulatory Matters - MISO Return on Equity Complaints (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2015
FERC Complaint 1 [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	9.15%
FERC Complaint 2 [Member]
Loss Contingencies [Line Items]
Proposed Return on Common Equity	8.67%
Minnesota Power [Member]
Loss Contingencies [Line Items]
Estimated Refund for MISO Revenue	$ 6.2
Estimated Refund for MISO Transmission Expense	4.1
Reserve	2.1
Reserve, Portion Attributable to Prior Years	$ 1.5

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

9 Months Ended

Sep. 30, 2015

Dec. 31, 2014

Regulatory Assets and Liabilities [Line Items]

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

Current Regulatory Assets

$ 16.3

Non-Current Regulatory Assets

353.3

357.3

Total Regulatory Assets

369.6

373.6

Non-Current Regulatory Liabilities

105.8

94.2

Wholesale and Retail Contra AFUDC [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

54.5

42.9

Plant Removal Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

20.9

22.8

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Liabilities

12.8

13.4

Deferred Fuel [Member]

Regulatory Assets and Liabilities [Line Items]

Current Regulatory Assets

16.3

^[1]

16.3

^[1]

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

212.3

^[2]

223.9

^[2]

Non-Current Regulatory Liabilities

1.8

^[2]

3.5

^[2]

Cost Recovery Riders [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

64.0

^[3]

59.7

^[3]

Income Taxes [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

46.9

46.6

Asset Retirement Obligations [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

20.5

17.8

PPACA Income Tax Deferral [Member]

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

5.0

Other

Regulatory Assets and Liabilities [Line Items]

Non-Current Regulatory Assets

4.6

4.3

Non-Current Regulatory Liabilities

$ 15.8

$ 11.6

[1]	Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
[2]	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 14. Pension and Other Postretirement Benefit Plans.)
[3]	The cost recovery rider regulatory assets are primarily due to capital expenditures related to the 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	3 Months Ended		9 Months Ended		0 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Oct. 30, 2015 Subsequent Event [Member]
Investment in ATC [Abstract]
Ownership Percentage	8.00%		8.00%
Cash Investments			$ 1.2	$ 3.1	$ 0.4
Equity Method Investment, Expected Additional Investment	0		0
Subsequent Event [Line Items]
Cash Investments			1.2	3.1	0.4
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2014			121.1
Cash Investments			1.2	3.1	0.4
Equity Earnings in ATC	5.5	5.3	14.1	15.6
Distributed ATC Earnings			(10.4)
Equity Investment Balance as of September 30, 2015	126.0		126.0
ATC Summarized Financial Data [Abstract]
Revenue	164.5	163.6	482.0	487.0
Operating Expense	78.0	76.6	238.3	229.6
Other Expense	23.1	21.4	71.7	65.1
Net Income	63.4	65.6	172.0	192.3
ALLETE's Equity in Net Income	$ 5.5	$ 5.3	$ 14.1	$ 15.6

Investment in ATC - FERC Complaints (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2015
Loss Contingencies [Line Items]
Approved Return on Common Equity	12.20%
Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Basis Point Reduction on Approved Rate of Return on Common Equity	50
After-tax [Member] \| Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Annual Effect on Future Equity Earnings in ATC	$ 0.5
Pre-tax [Member] \| Sensitivity Analysis [Member]
Sensitivity Analysis [Line Items]
Annual Effect on Future Equity Earnings in ATC	0.9
FERC Complaint 1 [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Proposed Return on Common Equity	9.15%
FERC Complaint 2 [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Proposed Return on Common Equity	8.67%
ALLETE Transmission Holdings [Member]
Loss Contingencies [Line Items]
Reserve Reflected in Equity Earnings in ATC	2.0
ALLETE Transmission Holdings [Member] \| FERC Complaint 2 [Member]
Loss Contingencies [Line Items]
Reserve Reflected in Equity Earnings in ATC	$ 1.1

Short-Term and Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended			0 Months Ended		0 Months Ended		0 Months Ended
	Sep. 24, 2015	Sep. 30, 2015	Dec. 31, 2014	Aug. 25, 2015 ALLETE Term Loan Variable Rate Due 2017 [Member]	Aug. 25, 2015 ALLETE Term Loan Variable Rate Due 2017 [Member]	Sep. 24, 2015 ALLETE Bonds 2.80% Due September 2020 [Member]	Sep. 24, 2015 ALLETE Bonds 2.80% Due September 2020 [Member]	Sep. 24, 2015 ALLETE Bonds 3.86% Due September 2030 [Member]	Sep. 24, 2015 ALLETE Bonds 3.86% Due September 2030 [Member]	Jul. 01, 2015 Armenia Mountain [Member]
Short-Term and Long-Term Debt [Line Items]
Short-Term Debt Outstanding		$ 49.1	$ 104.4
Long-Term Debt Outstanding		1,549.0	1,272.8
Business Combination, Long-Term Debt Assumed Including Current Portion										60.9
Business Combination, Current Portion of Long-Term Debt Assumed										5.9
Principal Amount					125.0
Variable Rate Basis				LIBOR
Basis Spread on Variable Rate				0.625%
Debt Refinanced				75.0
Required Indebtedness to Total Capitalization Ratio		0.65			0.65
Cross-Default Amount					35.0
Proceeds from Issuance of First Mortgage Bonds	$ 100.0					$ 40.0		$ 60.0
Interest Rate							2.80%		3.86%

Other Income (Expense) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Other Income (Expense) [Abstract]
AFUDC–Equity	$ 1.0	$ 2.1	$ 2.6	$ 5.9
Gain on Sale of Available-for-sale Securities	0	0	0.1	0.2
Investments and Other Income	0.7		0.8
Investments and Other Expense		0		(0.1)
Total Other Income	$ 1.7	$ 2.1	$ 3.5	$ 6.0

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

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Current Tax Expense [Abstract]

Federal

$ 0

^[1]

$ 0

^[1]

$ 0

^[1]

$ 0

^[1]

State

0.2

^[1],[2]

1.8

^[1],[2]

0.5

^[1],[2]

1.9

^[1],[2]

Total Current Tax Expense

0.2

1.8

0.5

1.9

Deferred Tax Expense (Benefit) [Abstract]

Federal

14.8

11.2

23.5

20.4

State

(0.4)

0.7

3.6

5.4

Investment Tax Credit Amortization

(0.2)

(0.3)

(0.6)

Total Deferred Tax Expense

14.2

11.6

26.5

25.2

Total Income Tax Expense

14.4

13.4

27.0

27.1

Effective Tax Rate

18.00%

22.70%

Combined Federal and State Statutory Tax Rate

41.00%

Reconciliation of Taxes from Federal Statutory Rate to Total Income Tax Expense [Abstract]

Income Before Non-Controlling Interest and Income Taxes

74.7

55.0

149.7

119.4

Statutory Federal Income Tax Rate

35.00%

Income Taxes Computed at 35 percent Statutory Federal Rate

52.4

41.8

Increase (Decrease) in Tax [Abstract]

State Income Taxes – Net of Federal Income Tax Benefit

2.6

4.8

Production Tax Credits

(27.0)

(16.4)

Regulatory Differences for Utility Plant

(0.7)

(2.1)

Other

(0.3)

(1.0)

Total Income Tax Expense

14.4

13.4

27.0

27.1

Uncertain Tax Positions [Abstract]

Gross Unrecognized Tax Benefits

2.9

2.0

Unrecognized Tax Benefits That Would Favorably Impact Effective Tax Rate

$ 0.4

[1]	For the quarter and nine months ended September 30, 2015, the federal and state current tax expense was minimal due to the utilization of NOL carryforwards from prior periods. The NOL carryforwards resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.
[2]	For the quarter and nine months ended September 30, 2014, the state current tax expense reflected initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired due to NOL carryforwards from prior periods. State NOL and alternative minimum tax carryforwards remaining after utilization in 2015 will be carried forward to offset future income.

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

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Income (Loss)

$ (20.2)

$ (16.3)

$ (21.1)

$ (17.1)

Other Comprehensive Income Before Reclassifications

(0.7)

(0.1)

(0.3)

0.2

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

0.3

0.8

Net Other Comprehensive Income (Loss)

(0.4)

0.2

0.5

1.0

Ending Accumulated Other Comprehensive Loss

(20.6)

(16.1)

(20.6)

(16.1)

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

(0.5)

(1.6)

(1.5)

Other Income (Expense) [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

0.1

^[1]

0.2

^[1]

Income Tax Expense [Member]

Reclassifications Out of Accumulated Other Comprehensive Income [Abstract]

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

^[2]

(0.1)

^[2]

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

0.2

^[2]

0.2

^[2]

0.7

^[2]

0.6

^[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, Prior Service Costs, Before Tax

0.1

^[3]

0.1

^[3]

0.3

^[3]

0.3

^[3]

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

(0.6)

^[3]

(0.6)

^[3]

(1.9)

^[3]

(1.8)

^[3]

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

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Income (Loss)

(0.2)

0.1

(0.3)

(0.1)

Other Comprehensive Income Before Reclassifications

(0.7)

(0.1)

(0.5)

0.2

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

(0.1)

Net Other Comprehensive Income (Loss)

(0.7)

(0.1)

(0.6)

0.1

Ending Accumulated Other Comprehensive Loss

(0.9)

Defined Benefit Pension and Other Postretirement Items [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Income (Loss)

(20.0)

(16.1)

(20.7)

(16.7)

Other Comprehensive Income Before Reclassifications

(0.1)

0.1

(0.1)

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

0.3

0.9

Net Other Comprehensive Income (Loss)

0.3

0.2

1.0

0.8

Ending Accumulated Other Comprehensive Loss

(19.7)

(15.9)

(19.7)

(15.9)

Gains and Losses on Cash Flow Hedge [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Beginning Accumulated Other Comprehensive Income (Loss)

(0.3)

(0.1)

(0.3)

Other Comprehensive Income Before Reclassifications

0.1

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

Net Other Comprehensive Income (Loss)

0.1

Ending Accumulated Other Comprehensive Loss

$ 0

$ (0.2)

$ 0

$ (0.2)

[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 14. Pension and Other Postretirement Benefit Plans.)

Earnings Per Share and Common Stock (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended		0 Months Ended					0 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Feb. 04, 2015 Forward Contracts [Member]	Sep. 05, 2014 Forward Contracts [Member]	Feb. 26, 2014 Forward Contracts [Member]	Feb. 04, 2015 Forward Contracts [Member]	Sep. 05, 2014 Forward Contracts [Member]	Mar. 04, 2014 Options Held [Member]
Earnings Per Share and Common Stock [Abstract]
Antidilutive Shares Excluded from Diluted EPS Computation			0	0
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 60.4	$ 41.6	$ 122.8	$ 91.9
Average Common Shares	48.8	42.9	48.0	42.1
Earnings Per Share	$ 1.24	$ 0.97	$ 2.56	$ 2.18
Earnings Per Share - Diluted [Abstract]
Net Income to Attributable ALLETE	60.4	41.6	122.8	91.9
Average Common Shares	48.9	42.9	48.1	42.3
Earnings Per Share	$ 1.23	$ 0.97	$ 2.55	$ 2.17
Dilutive Securities (in shares)	0.1	0	0.1	0.2
Proceeds from Issuance of Common Stock - Pension Plan			0	19.5
Common Stock Issued - Pension Plan (in shares)				0.4
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 Issued - Forward Contract (in shares)								1.4	1.4	0.4
Proceeds from Issuance of Common Stock - Forward Contract					$ 65.4	$ 65.0				$ 20.2

Pension and Other Postretirement Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension [Member]
Components of Net Periodic Benefit Expense (Income) [Abstract]
Service Cost	$ 2.6	$ 2.0	$ 7.6	$ 6.2
Interest Cost	7.5	7.5	22.4	22.4
Expected Return on Plan Assets	(10.2)	(9.6)	(30.5)	(28.7)
Amortization of Prior Service Costs (Credits)	0	0.1	0.1	0.2
Amortization of Net Loss	4.4	3.6	13.4	10.7
Net Periodic Benefit Expense (Income)	4.3	3.6	13.0	10.8
Contributions			0	19.5
Estimated Future Contributions			0
Other Postretirement [Member]
Components of Net Periodic Benefit Expense (Income) [Abstract]
Service Cost	1.0	0.9	3.2	2.6
Interest Cost	1.8	1.8	5.4	5.5
Expected Return on Plan Assets	(2.7)	(2.5)	(8.2)	(7.7)
Amortization of Prior Service Costs (Credits)	(0.7)	(0.7)	(2.2)	(1.9)
Amortization of Net Loss	0.1	0.1	0.3	0.3
Net Periodic Benefit Expense (Income)	(0.5)	(0.4)	(1.5)	(1.2)
Contributions			0	0
Estimated Future Contributions			$ 0

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) (USD $)	9 Months Ended			7 Months Ended	9 Months Ended
	Sep. 30, 2015 Square Butte PPA [Member]	Sep. 30, 2014 Square Butte PPA [Member]	Sep. 30, 2015 Square Butte PPA [Member] Square Butte Coal-fired Unit [Member] MW	Dec. 31, 2014 Square Butte PPA [Member] Minnkota Power Sales Agreement [Member] Square Butte Coal-fired Unit [Member]	Sep. 30, 2015 Square Butte PPA [Member] Minnkota Power Sales Agreement [Member] Square Butte Coal-fired Unit [Member]	Sep. 30, 2015 Minnkota Power PPA [Member] MW	Sep. 30, 2015 Oliver Wind I PPA [Member] MW	Sep. 30, 2015 Oliver Wind II PPA [Member] MW	Sep. 30, 2015 Manitoba Hydro PPA (expires May 2020) [Member] MW	Sep. 30, 2015 Manitoba Hydro PPA (expires April 2022) [Member] MWh	Sep. 30, 2015 Manitoba Hydro PPA (expires 2035) [Member] Years MW	Sep. 30, 2015 Manitoba Hydro PPA (expires 2040) [Member] Years MW	Sep. 30, 2015 Great River Energy and Capacity PPA (expires May 2020) [Member] MW	Sep. 30, 2015 Great River Capacity Only PPA (expires May 2020) [Member] MW	Sep. 30, 2015 TransAlta Off-Peak Hours PPA (expires 2019) [Member] MW	Sep. 30, 2015 TransAlta On-Peak Hours PPA (expire 2019) [Member] MW
Power Purchase Agreements [Line Items]
Generating Unit Capacity (MW)			455
Output Entitlement			50.00%	23.00%	28.00%
PPA Counterparty Debt Outstanding	$ 377,900,000
Annual Debt Service	45,000,000
Power Purchased under Long-term Contracts	57,600,000	51,800,000
Interest Expense	7,600,000	7,900,000
Output Being Purchased (MW)						50	50	48	50		250	133	50	50	50	100
Fixed Capacity Charges							$ 0	$ 0
Output Being Purchased (MWh)										1,000,000
Term of Contract (Years)											15	20

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) (Coal Supply and Transportation Agreements [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2015
Coal Supply and Transportation Agreements [Member]
Coal, Rail and Shipping Contracts [Line Items]
Minimum Annual Payment Obligation for Remainder of 2015	$ 13.9
Minimum Annual Payment Obligation in 2016	37.4
Minimum Annual Payment Obligation in 2017	27.6
Minimum Annual Payment Obligation in 2018	28.3
Minimum Annual Payment Obligation in 2019	$ 1.8

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2015
Leasing Agreements [Line Items]
Operating Leases, Minimum Payments Due in 2015	$ 15.0
Operating Leases, Minimum Payments Due in 2016	12.9
Operating Leases, Minimum Payments Due in 2017	11.8
Operating Leases, Minimum Payments Due in 2018	10.4
Operating Leases, Minimum Payments Due in 2019	9.3
Operating Leases, Minimum Payments Due Thereafter	29.1
BNI Coal Dragline Lease [Member]
Leasing Agreements [Line Items]
Operating Leases, Minimum Payments Due in 2015	2.8
Operating Leases, Minimum Payments Due in 2016	2.8
Operating Leases, Minimum Payments Due in 2017	2.8
Operating Leases, Minimum Payments Due in 2018	2.8
Operating Leases, Minimum Payments Due in 2019	2.8
Operating Leases, Minimum Payments Due Thereafter	22.4
Termination Fee	$ 3.0

Commitments, Guarantees and Contingencies - Transmission (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2015
CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	3
Capital Expenditures	$ 100
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
Completed Projects - Current Year [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	1
Completed Projects - Prior Years [Member] \| CapX2020 [Member]
Transmission [Line Items]
Number of CapX2020 Projects	2

Commitments, Guarantees and Contingencies - Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2015
Boswell Unit 4 [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures	$ 260
Capital Expenditures to Date	207
Maximum [Member] \| Clean Water Act - Aquatic Organisms [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	15
Maximum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	100
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Additional Wind Generating Capacity (MW)	200.0
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	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
U.S. Water Services [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 0.8
BNI Coal Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	47.5
BNI Coal Reclamation Liability [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.6
BNI Coal Reclamation Liability [Member] \| Surety Bonds [Member]
Guarantor Obligations [Line Items]
Collateral	49.9
ALLETE Properties Development and Maintenance Obligations [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	6.2
ALLETE Properties Development and Maintenance Obligations [Member] \| Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	10.8
Town Center Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Ownership Percentage of Benefited Property	72.00%	72.00%
Annual Assessment	1.4
Palm Coast Park Community Development District Obligation [Member]
Guarantor Obligations [Line Items]
Ownership Percentage of Benefited Property	93.00%	93.00%
Annual Assessment	$ 2.1

Regulatory Matters - Conservation Improvement Program (CIP) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Conservation Improvement Program [Abstract]
CIP Energy-Savings Goal	1.50%
CIP Financial Incentive	$ 6.2	$ 8.7

Regulatory Matters - Integrated Resource Plan (Details) (Natural Gas-Fired [Member])	Sep. 30, 2015 MW
Minimum [Member]
Generation [Line Items]
Generating Capacity (MW)	200
Maximum [Member]
Generation [Line Items]
Generating Capacity (MW)	300

Regulatory Matters - Boswell Mercury Emissions Reduction Plan (Details) (Boswell Unit 4 [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2015
Boswell Unit 4 [Member]
Schedule of Utility Generating Facilities [Line Items]
Estimated Capital Expenditures	$ 260
Capital Expenditures to Date	$ 207

Short-Term and Long-Term Debt - Financial Covenants (Details)	Sep. 30, 2015
Financial Covenants [Abstract]
Required Indebtedness to Total Capitalization Ratio	0.65
Actual Indebtedness to Total Capitalization Ratio	0.47