Long-Term Debt Due Within One Year

98.9

68.1

Total Assets

^[1]

4,857.6

4,894.5

Current Liabilities [Abstract]

Accounts Payable

64.8

88.8

Accrued Taxes

37.7

44.0

Accrued Interest

17.8

18.6

64.5

35.7

Notes Payable

0.9

1.6

Total Current Liabilities

85.9

86.1

271.6

274.8

Long-Term Debt

1,498.9

1,556.7

Deferred Income Taxes

595.1

579.8

Regulatory Liabilities

94.6

105.0

Defined Benefit Pension and Other Postretirement Benefit Plans

204.5

206.8

Other Non-Current Liabilities

340.8

349.0

Total Liabilities

3,005.5

3,072.1

Commitments, Guarantees and Contingencies (Note 13)

ALLETE's Equity [Abstract]

Common Stock Without Par Value, 80.0 Shares Authorized, 49.4 and 49.1 Shares Outstanding

1,283.5

1,271.4

Accumulated Other Comprehensive Loss

(24.2)

(24.5)

Retained Earnings

592.8

573.3

Total ALLETE Equity

1,852.1

1,820.2

Non-Controlling Interest in Subsidiaries

0.0

2.2

Total Equity

1,852.1

1,822.4

Total Liabilities and Equity

$ 4,857.6

$ 4,894.5

[1]

As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been revised to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 1.5	$ 1.0
Common Stock [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	49.4	49.1

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Operating Revenue	$ 314.8	$ 323.3	$ 648.6	$ 643.3
Operating Expenses [Abstract]
Fuel and Purchased Power	78.1	80.1	155.0	166.1
Transmission Services	16.1	11.3	32.9	26.2
Cost of Sales	33.4	52.3	66.7	83.5
Operating and Maintenance	82.0	85.4	160.1	165.1
Depreciation and Amortization	48.7	41.3	96.8	80.3
Taxes Other than Income Taxes	14.3	13.4	28.1	26.2
Total Operating Expenses	272.6	283.8	539.6	547.4
Operating Income	42.2	39.5	109.0	95.9
Other Income (Expense) [Abstract]
Interest Expense	(17.4)	(16.2)	(34.3)	(31.3)
Equity Earnings in ATC	4.1	4.7	8.9	8.6
Other	0.6	0.7	1.6	1.8
Total Other Expense	(12.7)	(10.8)	(23.8)	(20.9)
Income Before Non-Controlling Interest and Income Taxes	29.5	28.7	85.2	75.0
Income Tax Expense	4.7	6.4	14.0	12.6
Net Income	24.8	22.3	71.2	62.4
Less: Non-Controlling Interest in Subsidiaries	0.0	(0.2)	0.5	0.0
Net Income Attributable to ALLETE	$ 24.8	$ 22.5	$ 70.7	$ 62.4
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (in shares)	49.3	48.6	49.2	47.7
Diluted (in shares)	49.5	48.7	49.3	47.8
Basic Earnings Per Share of Common Stock	$ 0.50	$ 0.46	$ 1.44	$ 1.31
Diluted Earnings Per Share of Common Stock	0.50	0.46	1.43	1.30
Dividends Per Share of Common Stock	$ 0.52	$ 0.505	$ 1.04	$ 1.01

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Comprehensive Income [Abstract]
Net Income	$ 24.8	$ 22.3	$ 71.2	$ 62.4
Other Comprehensive Income [Abstract]
Unrealized Gain on Securities Net of Income Taxes of $0.3, $–, $–, and $0.1	0.4	0.0	0.0	0.1
Unrealized Gain on Derivatives Net of Income Taxes of $–, $0.1, $–, and $0.1	0.0	0.0	0.0	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans Net of Income Taxes of $0.1, $0.2, $0.2, and $0.4	0.1	0.4	0.3	0.7
Total Other Comprehensive Income	0.5	0.4	0.3	0.9
Total Comprehensive Income	25.3	22.7	71.5	63.3
Less: Non-Controlling Interest in Subsidiaries	0.0	(0.2)	0.5	0.0
Total Comprehensive Income Attributable to ALLETE	$ 25.3	$ 22.9	$ 71.0	$ 63.3

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Unrealized Gain on Securities, Income Taxes	$ 0.3	$ 0.0	$ 0.0	$ 0.1
Unrealized Gain on Derivatives, Income Taxes	0.0	0.1	0.0	0.1
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Taxes	$ 0.1	$ 0.2	$ 0.2	$ 0.4

Consolidated Statement of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating Activities [Abstract]
Net Income	$ 71.2	$ 62.4
Allowance for Funds Used During Construction – Equity	(1.2)	(1.6)
Income from Equity Investments – Net of Dividends	(2.9)	(2.3)
Gain on Sales of Investments	0.0	(0.1)
Depreciation Expense	94.2	78.7
Amortization of Power Purchase Agreements	(11.1)	(11.0)
Amortization of Other Intangible Assets and Other Assets	5.0	2.9
Deferred Income Tax Expense	13.8	12.3
Share-Based Compensation Expense	1.3	1.3
ESOP Compensation Expense	0.9	4.9
Defined Benefit Pension and Postretirement Benefit Expense	2.6	7.7
Bad Debt Expense	1.1	0.3
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	6.5	17.3
Inventories	6.7	(13.4)
Prepayments and Other	(0.8)	4.2
Accounts Payable	1.3	(25.6)
Other Current Liabilities	(18.5)	47.4
Changes in Regulatory and Other Non-Current Assets	(21.0)	(9.6)
Changes in Regulatory and Other Non-Current Liabilities	(2.9)	6.5
Cash from Operating Activities	146.2	182.3
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	1.4	0.7
Payments for Purchase of Available-for-sale Securities	(1.2)	(0.8)
Acquisitions of Subsidiaries – Net of Cash Acquired	0.0	(214.4)
Investment in ATC	(1.6)	(0.8)
Changes to Other Investments	2.1	(0.4)
Additions to Property, Plant and Equipment	(74.8)	(140.5)
Cash in Escrow for Acquisition	0.0	15.0
Proceeds from Sale of Property, Plant and Equipment	0.2	0.0
Cash for Investing Activities	(73.9)	(371.2)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	15.2	148.2
Proceeds from Issuance of Long-Term Debt	2.2	15.0
Changes in Restricted Cash	(2.0)	(2.9)
Changes in Notes Payable	(0.7)	(3.7)
Repayments of Long-Term Debt	(32.1)	(3.4)
Acquisition of Non-Controlling Interest	(8.0)	0.0
Acquisition-Related Contingent Consideration Payments	(0.7)	0.0
Debt Issuance Costs	(0.1)	0.0
Dividends on Common Stock	(51.2)	(49.5)
Cash from (for) Financing Activities	(77.4)	103.7
Change in Cash and Cash Equivalents	(5.1)	(85.2)
Cash and Cash Equivalents at Beginning of Period	97.0	145.8
Cash and Cash Equivalents at End of Period	$ 91.9	$ 60.6

Consolidated Statement of Equity Consolidated Statement of Equity - 6 months ended Jun. 30, 2016 - USD ($) $ in Millions	Total	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Common Stock [Member]	Non-Controlling Interest in Subsidiaries [Member]
Beginning Balance at Dec. 31, 2015	$ 1,822.4	$ 573.3	$ (24.5)	$ 1,271.4	$ 2.2
Comprehensive Income [Abstract]
Net Income	71.2	70.7			0.5
Other Comprehensive Income – Net of Tax [Abstract]
Defined Benefit Pension and Other Postretirement Plans – Net of Tax	0.3		0.3
Total Comprehensive Income	71.5
Common Stock Issued	17.4			17.4
Dividends Declared	(51.2)	(51.2)
Acquisition of Non-Controlling Interest	(8.0)			(5.3)	(2.7)
Ending Balance at Jun. 30, 2016	$ 1,852.1	$ 592.8	$ (24.2)	$ 1,283.5	$ 0.0

Operations and Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

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



Inventories	June 30, 2016			December 31, 2015
Millions
Fuel (a)		$49.2			$58.1
Materials and Supplies	49.8			49.1
Raw Materials	2.8			2.7
Work in Progress	0.6			—
Finished Goods	8.3			7.5
Reserve for Obsolescence	(0.3		)	(0.3		)
Total Inventories		$110.4			$117.1


(a)	Fuel consists primarily of coal inventory at Minnesota Power.



Prepayments and Other Current Assets	June 30, 2016		December 31, 2015
Millions
Deferred Fuel Adjustment Clause		$14.5		$10.6
Restricted Cash (a)	7.5		5.6
Other	16.4		19.5
Total Prepayments and Other Current Assets		$38.4		$35.7


(a)	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and cash pledged as collateral for U.S. Water Services’ standby letters of credit.

Other Non-Current Assets. As of June 30, 2016, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash related to collateral deposits required under ALLETE Clean Energy’s loan agreements and PPAs of $8.2 million ($8.1 million as of December 31, 2015). Also included in Other Non-Current Assets on the Consolidated Balance Sheet as of June 30, 2016, was a $31 million contract payment made to Cliffs as part of a long-term power sales agreement between Minnesota Power and Silver Bay Power. (See Note 13. Commitments, Guarantees and Contingencies.) The contract payment will be amortized over the term of the sales agreement.



Other Current Liabilities	June 30, 2016		December 31, 2015
Millions
Customer Deposits		$13.4		$15.1
Power Purchase Agreements	23.9		23.3
Other	48.6		47.7
Total Other Current Liabilities		$85.9		$86.1

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Non-Current Liabilities	June 30, 2016		December 31, 2015
Millions
Asset Retirement Obligation		$135.2		$131.4
Power Purchase Agreements	125.9		138.1
Contingent Consideration (a)	37.3		36.6
Other	42.4		42.9
Total Other Non-Current Liabilities		$340.8		$349.0


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 3. Acquisitions and Note 5. Fair Value.)

Supplemental Statement of Cash Flows Information.



Six Months Ended June 30,	2016		2015
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$32.9		$30.0
Cash Paid During the Period for Income Taxes		$0.4		$1.0
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(24.4)		$(25.5)
Capitalized Asset Retirement Costs		$2.3		$7.8
AFUDC–Equity		$1.2		$1.6
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.

New Accounting Standards.

Amendments to the Consolidation Analysis. In February 2015, the FASB issued revised guidance which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The new standard affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our Consolidated Financial Statements.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). In May 2015, the FASB issued an accounting standard update which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share (or its equivalent) practical expedient. The guidance applies to investments for which there is not a readily determinable fair value (market quote) or the investment is in a mutual fund without a publicly available net asset value. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our 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. This guidance was adopted in the first quarter of 2016 resulting in the reclassification of unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. The effect of the adoption decreased Total Assets and Total Liabilities on ALLETE's Consolidated Balance Sheet by $12.6 million as of December 31, 2015.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Standards (Continued)

Leases. In February 2016, the FASB issued an accounting standard update which revises the existing guidance for leases. Under the revised guidance, lessees will be required to recognize a “right-of-use” asset and a lease liability for all leases with a term greater than 12 months. The new standard also requires additional quantitative and qualitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement and presentation of expenses and cash flows from leases are not expected to significantly change as a result of the updated guidance. The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. The Company is evaluating the impact of the amended lease guidance on the Company’s Consolidated Financial Statements.

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. The guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s Consolidated Financial Statements.

Investments

6 Months Ended

Jun. 30, 2016

Acquisitions [Text Block]

Investments [Text Block]

INVESTMENTS

Investments. As of June 30, 2016, the investment portfolio included the legacy 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	June 30, 2016		December 31, 2015
Millions
ALLETE Properties		$47.8		$50.1
Available-for-sale Securities (a)	18.4		18.5
Cash Equivalents	2.3		2.0
Other	3.8		4.0
Total Other Investments		$72.3		$74.6


(a)	As of June 30, 2016, 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 $2.5 million, in three years to less than five years was $5.0 million, and in five or more years was $3.3 million.

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 estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairments were recorded for the quarter and six months ended June 30, 2016.

Acquisitions

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

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 six months ended June 30, 2016 and 2015.

2016 Activity.

Acquisition of Non-Controlling Interest. On April 15, 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns its Condon wind energy facility for $8.0 million. This transaction was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income. As a result of the acquisition, the Condon wind energy facility is now a wholly-owned subsidiary of ALLETE Clean Energy.

2015 Activity.

U.S. Water Services. In February 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, as estimated at the date of acquisition, 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.

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 purchase price accounting, which was finalized in 2015, is reflected in the following table. 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
Intangible Assets (c)	83.0
Goodwill (d)	122.9
Other Non-Current Assets	0.2
Total Assets Acquired		$253.1
Liabilities Assumed
Current Liabilities		$19.2
Non-Current Liabilities	31.6
Total Liabilities Assumed		$50.8
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 were 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 was 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 standby letters of credit.


(c)	Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 4. Goodwill and Intangible Assets.)


(d)	For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill.

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

NOTE 3. ACQUISITIONS (Continued)

2015 Activity (Continued)

Chanarambie/Viking. In April 2015, ALLETE Clean Energy acquired 100 percent of 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).



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 PPAs.

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

Armenia Mountain. In July 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.

NOTE 3. ACQUISITIONS (Continued)

2015 Activity (Continued)



Millions
Assets Acquired
Current Assets (a)	$9.0
Property, Plant and Equipment	156.2
Other Non-Current Assets (b)	14.4
Total Assets Acquired		$179.6
Liabilities Assumed
Current Liabilities		$2.9
Long-Term Debt Due Within One Year	5.9
Long-Term Debt	55.0
Other Non-Current Liabilities	4.7
Total Liabilities Assumed	$68.5
Net Identifiable Assets Acquired		$111.1


(a)	Included in Current Assets was $1.0 million related to the current portion of PPAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.


(b)	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PPAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements, and an immaterial amount 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 throughout the second and third quarters of 2015, and recorded in Operating and Maintenance on the Consolidated Statement of Income.

A and W Technologies. In November 2015, U.S. Water Services acquired 100 percent of A and W Technologies, Inc. (AWT). Total consideration for the transaction was $9.3 million, which included payment of $8.3 million in cash and a $1.0 million payment due in April 2017. AWT, similar to U.S. Water Services, is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southeastern United States.



Millions
Assets Acquired
Current Assets	$1.0
Property, Plant and Equipment	0.1
Intangible Assets (a)	3.9
Goodwill (b)	4.4
Total Assets Acquired		$9.4
Liabilities Assumed
Current Liabilities		$0.1
Total Liabilities Assumed	$0.1
Net Identifiable Assets Acquired		$9.3


(a)	Intangible Assets include customer relationships and non-compete agreements. (See Note 4. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill.

Acquisition-related costs were immaterial, expensed as incurred during the fourth quarter of 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Goodwill and Intangible Assets Disclosure [Abstract]

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).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4845-128472

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1500-128463

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-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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+ Details

Goodwill and Intangible Assets

6 Months Ended

Jun. 30, 2016

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The aggregate carrying amount of goodwill was $130.6 million as of June 30, 2016, and December 31, 2015. There have been no changes to goodwill by reportable segment for the six months ended June 30, 2016.

Balances of intangible assets, net, excluding goodwill as of June 30, 2016, are as follows:



	December 31, 2015		Amortization	June 30, 2016
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	$60.8		$(2.1)		$58.7
Developed Technology and Other (a)	7.2		(0.4)	6.8
Total Definite-Lived Intangible Assets	68.0		(2.5)	65.5
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		n/a	16.6
Total Intangible Assets		$84.6	$(2.5)		$82.1


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

Customer relationships have a remaining useful life of approximately 22 years and developed technology and other have remaining useful lives ranging from approximately 3 years to approximately 13 years (weighted average of approximately 8 years). The weighted average remaining useful life of all definite-lived intangible assets as of June 30, 2016, is approximately 20 years.

Amortization expense of intangible assets for the six months ended June 30, 2016, was $2.5 million. Accumulated amortization was $6.6 million as of June 30, 2016 ($4.1 million as of December 31, 2015). The estimated amortization expense for definite-lived intangible assets for the remainder of 2016 is $2.6 million. Estimated annual amortization expense for definite-lived intangible assets is $5.0 million in 2017, $4.7 million in 2018, $4.4 million in 2019, $4.2 million in 2020 and $44.6 million thereafter.

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

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [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 2015 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 June 30, 2016, and December 31, 2015. 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 following tables.

NOTE 5. FAIR VALUE (Continued)



	Fair Value as of June 30, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.4	—		—			$7.4
Available-for-sale – Corporate Debt Securities	—			$11.0	—		11.0
Cash Equivalents	2.3		—		—		2.3
Total Fair Value of Assets		$9.7		$11.0	—			$20.7

Liabilities (b)
Deferred Compensation	—			$15.9	—			$15.9
U.S. Water Services Contingent Consideration	—		—			$37.3	37.3
Total Fair Value of Liabilities	—			$15.9		$37.3		$53.2
Total Net Fair Value of Assets (Liabilities)		$9.7	$(4.9)		$(37.3)		$(32.5)


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


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



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.6	—		—			$7.6
Available-for-sale – Corporate Debt Securities	—			$10.9	—		10.9
Cash Equivalents	2.0		—		—		2.0
Total Fair Value of Assets		$9.6		$10.9	—			$20.5

Liabilities (b)
Deferred Compensation	—			$16.1	—			$16.1
U.S. Water Services Contingent Consideration	—		—			$36.6	36.6
Total Fair Value of Liabilities	—			$16.1		$36.6		$52.7
Total Net Fair Value of Assets (Liabilities)		$9.6	$(5.2)		$(36.6)		$(32.2)


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


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

The Level 3 activity in the preceding tables is the result of the February 2015 acquisition of U.S. Water Services. Changes in the fair value of U.S. Water Services’ Contingent Consideration for the six months ended June 30, 2016, are primarily due to accretion expense.

For the six months ended June 30, 2016, and the year ended December 31, 2015, 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 Long-Term Debt Due Within One Year
June 30, 2016	$1,575.2	$1,647.6
December 31, 2015	$1,605.0	$1,676.0

NOTE 5. FAIR VALUE (Continued)

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. For the six months ended June 30, 2016, and the year ended December 31, 2015, there were no indicators of impairment for these non-financial assets.

Regulatory Matters [Text Block]

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

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

REGULATORY MATTERS

Regulatory matters are summarized in Note 5. Regulatory Matters to our Consolidated Financial Statements in our 2015 Form 10-K, with additional disclosure provided in the following paragraphs.

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. Subsequent to this order, and as authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for environmental, renewable and transmission investments. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Boswell Mercury Emissions Reduction Plan.) Revenue from cost recovery riders was $48.9 million for the six months ended June 30, 2016 ($44.9 million for the six months ended June 30, 2015).

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The state of Minnesota enacted an EITE customer ratemaking law in June 2015 which established that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. In November 2015, Minnesota Power filed a rate schedule petition for EITE customers and a corresponding rider for EITE cost recovery with the MPUC. The rate proposal was revenue and cash flow neutral to Minnesota Power. In an order dated March 23, 2016, the MPUC dismissed the petition without prejudice, providing Minnesota Power the option to refile the petition with additional information or file a new petition. On June 30, 2016, Minnesota Power filed a revised EITE petition with the MPUC, which includes additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount.

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All of the wholesale contracts include a termination clause requiring a three-year notice to terminate.

In April 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 SWL&P and one other municipal customer are effective through June 30, 2019. The rates included in these three 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 14 municipal customers, extending the contract terms through December 31, 2024. These contracts include fixed capacity charges through 2018; beginning in 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 determined using a cost-based formula methodology. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.

In January 2016, one of Minnesota Power’s municipal customers provided notice of its intent to terminate its contract effective June 30, 2019. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2025. Under the agreement with SWL&P, no termination notice may be given prior to July 31, 2016. The remaining 14 municipal customers may not give termination notices prior to December 31, 2021.

NOTE 6. REGULATORY MATTERS (Continued)

2016 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. On June 28, 2016, SWL&P filed a rate increase request with the PSCW requesting an average overall increase of 3.1 percent for retail customers (a 3.5 percent increase in electric rates, a 1.3 percent decrease in natural gas rates and a 7.8 percent increase in water rates). The rate filing seeks an overall return on equity of 10.9 percent, based on a capital structure consisting of approximately 55 percent equity and 45 percent debt. On an annualized basis, the requested rate increase would generate approximately $2.7 million in additional revenue. Hearings are expected to be scheduled in late 2016. The Company anticipates new rates will take effect during the first quarter of 2017. We cannot predict the level of rates that may be approved by the PSCW.

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 3, 2016, 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. As a result of the MPUC approval of the certificate of need for the GNTL in June 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 in 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 and the restoration and repair of Thomson. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated March 9, 2016, allowing Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested. While approving the updated customer billing rates for the renewable cost recovery rider, the MPUC also allowed Minnesota Power additional time to submit support for its position on its utilization of North Dakota investment tax credits.

Minnesota Power accounts for North Dakota investment tax credits based on long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in the ALLETE consolidated group. The Minnesota Department of Commerce (Department) has inquired about our use of the North Dakota investment tax credits, taking the position that all North Dakota investment tax credits generated from the Bison Wind Energy Center should be credited to Minnesota Power ratepayers. The MPUC did not come to a decision on this issue in its order dated March 9, 2016, but requested that Minnesota Power provide further support on its position which was submitted on April 8, 2016. On April 22, 2016, the Department submitted additional comments restating its position that the tax credits should be credited to ratepayers.

The amount of North Dakota investment tax credits recognized by ALLETE as of June 30, 2016, total approximately $8 million, which represents the amount of North Dakota investment tax credits that the Department believes should be refunded to ratepayers. Minnesota Power will appropriately consider all avenues of appeal should an adverse decision be issued by the MPUC.

Annual Automatic Adjustment (AAA) of Charges. In an order dated June 2, 2016, the MPUC approved Minnesota Power’s AAA filings made in 2012 and 2013, and deferred action for 90 days on the AAA filing made in 2014 pending review and confirmation of coal transportation costs and terms of service. Minnesota Power’s AAA filings made in 2014 and 2015 are pending MPUC approval, and represent approximately $350 million in retail fuel cost recovery collected, but subject to refund. Minnesota Power currently expects full recovery of amounts represented by each AAA filing, although we cannot predict the outcome of the MPUC’s review of our pending filings.

NOTE 6. REGULATORY MATTERS (Continued)

Integrated Resource Plan (IRP). In a November 2013 order, the MPUC approved Minnesota Power’s 2013 IRP which detailed its EnergyForward strategic plan, announced in January 2013. Significant elements of the EnergyForward plan include major wind investments in North Dakota completed in the fourth quarter of 2014, the installation of emissions control technology at Boswell Unit 4 completed in December 2015, 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. In September 2015, Minnesota Power filed its 2015 IRP with the MPUC which includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contains the next steps in Minnesota Power’s 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.

In an order dated July 18, 2016, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepts Minnesota Power’s plans for Taconite Harbor, directs Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, requires an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal and requires Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. Minnesota Power’s next IRP must be filed by February 1, 2018.

Boswell Mercury Emissions Reduction Plan. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Customer billing rates for the environmental improvement rider were approved by the MPUC in August 2015. In September 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.

Boswell Remaining Life Petition. In November 2015, Minnesota Power filed a petition with the MPUC for approval to extend Boswell’s remaining life to 2050 for all units and utilize the existing environmental improvement rider to credit a portion of the depreciation expense savings to customers. The extension request is based on the significant multi-emissions retrofit work done at Boswell Unit 3 and Boswell Unit 4.

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 a June 2015 order. 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 a December 2015 order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. 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 an order dated April 11, 2016, the MPUC approved the route permit which largely follows Minnesota Power’s preferred route, including the international border crossing. A final decision on the presidential permit by the U.S. Department of Energy is expected in the third 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 the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 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 requires electric utilities to spend a minimum of 1.5 percent of net gross operating revenues from service provided in the state on energy CIPs each year. On June 1, 2016, Minnesota Power submitted its CIP triennial filing for 2017 through 2019 with the Minnesota Department of Commerce, which outlines Minnesota Power’s CIP spending and energy-saving goals for 2017 through 2019. A decision on the CIP triennial filing by the Minnesota Department of Commerce is expected in the fourth quarter of 2016.

On April 1, 2016, Minnesota Power submitted its 2015 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $7.5 million based upon MPUC procedures. In an order dated July 19, 2016, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

NOTE 6. REGULATORY MATTERS (Continued)

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 and ATC, to 9.15 percent. In December 2015, a federal administrative law judge ruled on the November 2013 complaint proposing a reduction in the base return on equity to 10.32 percent, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2016.

In February 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. On June 30, 2016, a federal administrative law judge ruled on the February 2015 complaint proposing a further reduction in the base return on equity to 9.70 percent, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2017. On January 6, 2015, the FERC approved an incentive adder of up to 50 basis points on the allowed base return on equity for our participation in a regional transmission organization, subject to the outcome of the return on equity complaints.

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kW or less. Minnesota Power has two solar projects under development. In August 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at Camp Ripley, a Minnesota Army National Guard base and training facility near Little Falls, Minnesota. In an order dated February 24, 2016, the MPUC approved the Camp Ripley solar project as eligible to meet the solar energy standard and for current cost recovery, subject to certain compliance requirements. In September 2015, Minnesota Power filed for MPUC approval of a community solar garden project in Duluth, Minnesota, which is comprised of a 1 MW solar array to be owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that will be owned and operated by Minnesota Power. In an order dated July 27, 2016, the MPUC approved the community solar garden project and cost recovery, subject to certain compliance requirements. Minnesota Power believes these projects will meet approximately one-third of the overall mandate. Additionally, on June 1, 2016, Minnesota Power filed a proposal with the MPUC to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. If approved, Minnesota Power expects the projects to meet part of the mandate related to solar photovoltaic devices with a nameplate capacity of 20 kW or less.

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 of 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 6. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	June 30, 2016		December 31, 2015
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$14.5		$10.6
Total Current Regulatory Assets	14.5		10.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	215.0		219.3
Income Taxes (c)	64.7		64.2
Cost Recovery Riders (d)	47.2		58.0
Asset Retirement Obligations (e)	23.5		21.6
PPACA Income Tax Deferral	5.0		5.0
Other	3.7		3.9
Total Non-Current Regulatory Assets	359.1		372.0
Total Regulatory Assets		$373.6		$382.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$57.0		$58.0
Plant Removal Obligations	14.4		22.1
Income Taxes (c)	5.4		6.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	—		0.9
Other	17.8		17.9
Total Non-Current Regulatory Liabilities		$94.6		$105.0


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

(b)

Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)


(c)	These assets and liabilities are offsets to deferred income taxes recognized on certain regulatory temporary differences, which will reverse over the remaining lives of those temporary differences.

(d)

The cost recovery rider regulatory assets are revenues not yet collected from our customers 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. The cost recovery rider regulatory assets as of June 30, 2016, will be recovered over the next two years.


(e)	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.


(f)	Wholesale and Retail Contra AFUDC represents the regulatory offset to AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.

Investment in ATC

6 Months Ended

Jun. 30, 2016

Equity Method Investments and Joint Ventures [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 June 30, 2016, our equity investment in ATC was $129.0 million ($124.5 million at December 31, 2015). In the first six months of 2016, we invested $1.6 million in ATC, and on July 29, 2016, we invested an additional $1.9 million. We expect to make additional investments of approximately $2.7 million in 2016.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2015		$124.5
Cash Investments	1.6
Equity in ATC Earnings	8.9
Distributed ATC Earnings	(6.0		)
Equity Investment Balance as of June 30, 2016		$129.0

NOTE 7. INVESTMENT IN ATC (Continued)

Our equity earnings in ATC continue to be impacted by reductions for estimated refunds related to complaints filed with the FERC by several customer groups located within the MISO service area. (See Note 6. Regulatory Matters.) ATC's current authorized return on equity is 12.2 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 after-tax ($0.9 million pre-tax).

Short-Term and Long-Term Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

The following tables present ALLETE’s short-term and long-term debt as of June 30, 2016 and December 31, 2015.



June 30, 2016	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt (a)		$66.0	$(0.6)		$65.4
Long-Term Debt	1,510.1		(11.2)	1,498.9
Total Debt		$1,576.1	$(11.8)		$1,564.3


(a)	Consisted of long-term debt due within one year and notes payable.



December 31, 2015	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt (a)		$37.9	$(0.6)		$37.3
Long-Term Debt	1,568.7		(12.0)	1,556.7
Total Debt		$1,606.6	$(12.6)		$1,594.0


(a)	Consisted of long-term debt due within one year and notes payable.

No long-term debt was issued in the first six months of 2016.

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 June 30, 2016, our ratio was approximately 0.46 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 June 30, 2016, ALLETE was in compliance with its financial covenants.

Income Tax Expense

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Millions
Current Tax Expense (a)
Federal	—			—			—			—
State		$0.1		$0.2				$0.2		$0.3
Total Current Tax Expense		$0.1		$0.2				$0.2		$0.3
Deferred Tax Expense
Federal	$2.1				$3.9		$6.7				$8.7
State	2.7			2.5			7.5			4.0
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Total Deferred Tax Expense	$4.6				$6.2		$13.8				$12.3
Total Income Tax Expense	$4.7				$6.4		$14.0				$12.6


(a)	For the six months ended June 30, 2016 and 2015, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

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.



Reconciliation of Taxes from Federal Statutory
Rate to Total Income Tax Expense
Six Months Ended June 30	2016			2015
Millions
Income Before Non-Controlling Interest and Income Taxes		$85.2			$75.0
Statutory Federal Income Tax Rate	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$29.8			$26.3
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	5.0			2.8
Production Tax Credits	(20.5		)	(20.8		)
Regulatory Differences for Utility Plant	(0.1		)	(0.4		)
Other	(0.2		)	4.7
Total Income Tax Expense		$14.0			$12.6

For the six months ended June 30, 2016, the effective tax rate was 16.4 percent (16.8 percent for the six months ended June 30, 2015).

Uncertain Tax Positions. As of June 30, 2016, we had gross unrecognized tax benefits of $2.2 million ($2.4 million as of December 31, 2015). Of the total gross unrecognized tax benefits, $0.5 million represents the amount of unrecognized tax benefits included on 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 or state examination for years before 2012.

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Reclassifications Out of Accumulated Other Comprehensive Income (Loss) [Text Block]	RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Changes in Accumulated Other Comprehensive Loss. Comprehensive income (loss) is the change in shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale securities, defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits, and gains and losses on derivatives accounted for as cash flow hedges. For the quarter and six months ended June 30, 2016 and 2015, reclassifications out of accumulated other comprehensive income for the Company were not material. Changes in accumulated other comprehensive loss for the six months ended June 30, 2016, are presented on the Consolidated Statement of Equity.

Earnings Per Share and Common Stock [Text Block]

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

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

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 entered into in February 2014. For the six months ended June 30, 2016 and 2015, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share.



			2016					2015
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Quarter ended June 30,
Net Income Attributable to ALLETE		$24.8			$24.8		$22.5			$22.5
Average Common Shares	49.3		0.2	49.5		48.6		0.1	48.7
Earnings Per Share		$0.50			$0.50		$0.46			$0.46
Six Months Ended June 30,
Net Income Attributable to ALLETE		$70.7			$70.7		$62.4			$62.4
Average Common Shares	49.2		0.1	49.3		47.7		0.1	47.8
Earnings Per Share		$1.44			$1.43		$1.31			$1.30

Pension and Other Postretirement Benefit Plans

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [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)	2016			2015			2016			2015
Millions
Quarter Ended June 30,
Service Cost		$2.1			$2.5			$1.0			$1.1
Interest Cost	8.1			7.4			1.8			1.8
Expected Return on Plan Assets	(10.7		)	(10.1		)	(2.8		)	(2.8		)
Amortization of Prior Service Costs (Credits)	—			0.1			(0.8		)	(0.7		)
Amortization of Net Loss	2.5			4.5			0.1			0.1
Net Periodic Benefit Expense (Income)		$2.0			$4.4		$(0.7)			$(0.5)

Six Months Ended June 30,
Service Cost		$4.1			$5.0			$2.0			$2.2
Interest Cost	16.2			14.9			3.7			3.6
Expected Return on Plan Assets	(21.3		)	(20.3		)	(5.6		)	(5.5		)
Amortization of Prior Service Costs (Credits)	—			0.1			(1.5		)	(1.5		)
Amortization of Net Loss	4.9			9.0			0.1			0.2
Net Periodic Benefit Expense (Income)		$3.9			$8.7		$(1.3)			$(1.0)

NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Employer Contributions. For the six months ended June 30, 2016 and 2015, no contributions were made to our defined benefit pension plan; we expect to make $2.0 million in contributions to our defined benefit pension plan in 2016. For the six months ended June 30, 2016 and 2015, 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 2016.

Commitments, Guarantees and Contingencies

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [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.

Our PPAs are summarized in Note 12. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our 2015 Form 10-K, with additional disclosure provided in the following paragraphs.

Square Butte PPA. Minnesota Power has a PPA with Square Butte, a North Dakota cooperative corporation, that extends through 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal-fired generating unit. 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. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of June 30, 2016, Square Butte had total debt outstanding of $361.9 million. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during the six months ended June 30, 2016, was $37.7 million ($39.5 million for the six months ended June 30, 2015). 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 $4.8 million during the six months ended June 30, 2016 ($5.0 million for the six months ended June 30, 2015). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. Minnesota Power has a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, Minnesota Power is selling a portion of its entitlement 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. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2016 and in 2015.

Silver Bay Power Sales Agreement. On May 23, 2016, Minnesota Power and Silver Bay Power entered into a long-term power purchase agreement through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining which has been served predominately through self-generation by Silver Bay Power. In the years 2016 through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power will have the option to purchase additional energy from Minnesota Power as it transitions away from self-generation. On December 31, 2019, Silver Bay Power will cease self-generation and Minnesota Power will supply the entire energy requirements for Silver Bay Power.

Shell Energy PPA. In June 2016, Minnesota Power and Shell Energy signed a PPA that provides for Minnesota Power to purchase 50 MW of energy at fixed prices. The PPA begins in January 2017 and expires in December 2019.

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 2021. 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 $17.7 million for the remainder of 2016, $27.9 million in 2017, $27.0 million in 2018, $1.8 million in 2019 and none thereafter. 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 Energy is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term, which expires in 2027. BNI Energy 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 $14.0 million in 2016, $12.6 million in 2017, $11.1 million in 2018, $9.9 million in 2019, $6.9 million in 2020 and $23.2 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, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC.

Our transmission investments are summarized in Note 12. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our 2015 Form 10-K, with additional disclosure provided in the following paragraphs.

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 a June 2015 order. 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. (See Note 6. Regulatory Matters.) In a December 2015 order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. 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 an order dated April 11, 2016, the MPUC approved the route permit which largely follows Minnesota Power’s preferred route, including the international border crossing. A final decision on the presidential permit by the U.S. Department of Energy is expected in the third 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 the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 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. 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. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional regulation under many of these regulations. In response to these regulations, Minnesota Power is reshaping its generation portfolio over time to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

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. We anticipate that with many state and federal environmental regulations finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 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 IRP filed with the MPUC on September 1, 2015, outlined Minnesota Power’s preferred option to reroute emissions from Boswell 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). The 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. The 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 and beyond) for 2017 and 2018 were distributed on June 29, 2016. Based on our review of the NO_x and SO₂ Phase I and Phase II allowances already issued, and Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will result in compliance in both Phase I and Phase II.

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. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed in 2015. 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 June 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. In December 2015, the U.S. Court of Appeals for the D.C. Circuit rejected a motion by utilities and states to vacate the MATS rule, instead ordering the rule to remain in effect while the EPA completes its review. On April 15, 2016, the EPA announced its determination that the MATS rule is appropriate and necessary, even after considering cost of compliance. The outcome of these proceedings is not expected to have a material impact on Minnesota Power generation due to emission reduction obligations under the Minnesota Mercury Emissions Reduction Act and the Consent Decree. (See New Source Review.)

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 was required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above (see Mercury and Air Toxics Standards (MATS) Rule) fulfills 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 had until January 31, 2016, to achieve compliance with the final rule and July 29, 2016, to perform initial compliance demonstrations. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. Compliance consists largely of adjustments to our operating practices; therefore the costs for complying with the final rule are not expected to be material.

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 more stringent control related to 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. In October 2015, the EPA published the final rule in the Federal Register 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.

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 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In September 2013 the EPA provided guidance to states regarding implementation of the one-hour NO₂ NAAQS and in June 2014, as clarified in February 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. In October 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 NO₂, 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.

In August 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. On January 8, 2016, the MPCA informed the EPA of the Minnesota sources subject to the rule, confirming that Boswell and Taconite Harbor are the only Minnesota Power generating facilities subject to the DRR. The MPCA was required to notify the EPA how each source will evaluate air quality by July 1, 2016. The MPCA has 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 DRR also requires the MPCA to amend the operating permits for Boswell and Taconite Harbor by January 13, 2017, to include emissions limits at which one-hour SO₂ NAAQS compliance was modeled. Minnesota Power is assisting the MPCA to ensure this deadline will be met. Compliance costs for the one-hour SO₂ NAAQS are not expected to be material.

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 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.

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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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.

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”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in August 2015, together with a proposed federal implementation plan and a model rule for emissions trading. Numerous petitions for review of the rule have been filed with the U.S. Court of Appeals for the District of Columbia Circuit. On February 9, 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In May 2016, the U.S. Court of Appeals for the District of Columbia announced the petitions for review will be heard on September 27, 2016. The EPA is precluded from enforcing the CPP while the Supreme Court stay is in force; however, the MPCA has been holding a series of meetings on the CPP for educational and planning purposes in the interim. Minnesota Power has been actively involved in these MPCA meetings, and is closely monitoring the appeals process.

If upheld, the CPP would establish 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 SIP by September 6, 2016, or by September 6, 2018, if granted an extension. If the CPP is upheld at the completion of the appellate court process, all of the CPP regulatory deadlines may be reset based on the length of time that the appeals process takes.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 as well as its potential impact on the Company and is actively discussing potential compliance scenarios with regulatory agencies and in public stakeholder meetings. 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 6. 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, the U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 (NEGA) 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 PPAs 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. On June 15, 2016, the U.S. Court of Appeals for the Eighth Circuit upheld the federal district court’s decision that part of the NEGA violated the Commerce Clause of the U.S. Constitution.

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 effective 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 for Minnesota Power generating facilities 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. Minnesota Power 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 in September 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.

We are reviewing the final 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Coal Ash Management Facilities. Minnesota Power generates or disposes coal ash at four of its electric generating facilities. One facility stores ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility’s ash is beneficially re-used. The other 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 and it was published in the Federal Register in April 2015. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 10 years and be between approximately $65 million and $100 million. Minnesota Power has not disposed ash onsite at Taconite Harbor since the effective date of the rule, and therefore, the CCR rule is not applicable to that generating facility. Minnesota Power continues to work on minimizing costs 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’s wind energy facilities have PPAs in place for their entire output and expire in various years between 2018 and 2032. As of June 30, 2016, ALLETE Clean Energy has $14.6 million outstanding in standby letters of credit.

U.S. Water Services. As of June 30, 2016, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of June 30, 2016, BNI Energy had surety bonds outstanding of $49.9 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its 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 Energy has secured a letter of credit for an additional $0.6 million to provide for BNI Energy’s total reclamation liability, which is currently estimated at $47.5 million. BNI Energy 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 June 30, 2016, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.1 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $6.1 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. At June 30, 2016, we owned 72 percent of the assessable land in the Town Center District (72 percent at December 31, 2015) and 92 percent of the assessable land in the Palm Coast Park District (92 percent at December 31, 2015). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are approximately $1.4 million for Town Center at Palm Coast and $2.1 million for Palm Coast Park. As we sell property at these projects, 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.

Business Segments

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

During the third quarter of 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess, and allocate resources after our recent acquisitions. We 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 in February 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 Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy 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.



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Millions
Operating Revenue
Regulated Operations	$234.9			$230.0			$487.2			$492.8

Energy Infrastructure and Related Services
ALLETE Clean Energy	18.8			34.0			42.4			46.4
U.S. Water Services	34.3			34.4			66.7			49.9

Corporate and Other	26.8			24.9			52.3			54.2
Total Operating Revenue		$314.8			$323.3			$648.6			$643.3
Net Income (Loss) Attributable to ALLETE
Regulated Operations (a)		$22.6			$23.3			$65.0			$64.3

Energy Infrastructure and Related Services
ALLETE Clean Energy	2.6			3.0			8.7			5.5
U.S. Water Services	1.0			0.6			0.5			0.5

Corporate and Other (a)	(1.4		)	(4.4		)	(3.5		)	(7.9		)
Total Net Income Attributable to ALLETE		$24.8			$22.5			$70.7			$62.4


(a)	In 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries which is 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, 2015.



	June 30, 2016		December 31, 2015
Millions
Assets
Regulated Operations (a)	$3,823.4		$3,853.1

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	489.5		501.5
U.S. Water Services	258.2		258.3

Corporate and Other	286.5		281.6
Total Assets (a)		$4,857.6		$4,894.5


(a)	As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been revised to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

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+ Details

Operations and Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Inventories [Policy Text Block]	Inventories are stated at the lower of cost or market. Inventories in our Regulated Operations and ALLETE Clean Energy segments are carried at an average cost or first-in, first-out basis. Inventories in our U.S. Water Services and Corporate and Other segments are carried at an average cost, first-in, first-out or specific identification basis.
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]	Amendments to the Consolidation Analysis. In February 2015, the FASB issued revised guidance which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The new standard affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our Consolidated Financial Statements. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). In May 2015, the FASB issued an accounting standard update which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share (or its equivalent) practical expedient. The guidance applies to investments for which there is not a readily determinable fair value (market quote) or the investment is in a mutual fund without a publicly available net asset value. This guidance was adopted in the first quarter of 2016 and did not have a material impact on our 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. This guidance was adopted in the first quarter of 2016 resulting in the reclassification of unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. The effect of the adoption decreased Total Assets and Total Liabilities on ALLETE's Consolidated Balance Sheet by $12.6 million as of December 31, 2015. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) New Accounting Standards (Continued) Leases. In February 2016, the FASB issued an accounting standard update which revises the existing guidance for leases. Under the revised guidance, lessees will be required to recognize a “right-of-use” asset and a lease liability for all leases with a term greater than 12 months. The new standard also requires additional quantitative and qualitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement and presentation of expenses and cash flows from leases are not expected to significantly change as a result of the updated guidance. The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. The Company is evaluating the impact of the amended lease guidance on the Company’s Consolidated Financial Statements. 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. The guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s 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 estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairments were recorded for the quarter and six months ended June 30, 2016.
Acquisitions [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 purchase price accounting, which was finalized in 2015, is reflected in the following table. 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 purchase price accounting, which was finalized in 2015, is reflected in the following table. 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 purchase price accounting, which was finalized in 2015, is reflected in the following table. 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 purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
Fair Value Measurement [Policy Text Block]	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. 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.
North Dakota Investment Tax Credits [Policy Text Block]	Minnesota Power accounts for North Dakota investment tax credits based on long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in the ALLETE consolidated group.
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 of 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 entered into in February 2014. For the six months ended June 30, 2016 and 2015, no options to purchase shares of common stock were excluded from the computation of diluted earnings per share.
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)

6 Months Ended

Jun. 30, 2016

Inventories [Table Text Block]



Inventories	June 30, 2016			December 31, 2015
Millions
Fuel (a)		$49.2			$58.1
Materials and Supplies	49.8			49.1
Raw Materials	2.8			2.7
Work in Progress	0.6			—
Finished Goods	8.3			7.5
Reserve for Obsolescence	(0.3		)	(0.3		)
Total Inventories		$110.4			$117.1


(a)	Fuel consists primarily of coal inventory at Minnesota Power.

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	June 30, 2016		December 31, 2015
Millions
Deferred Fuel Adjustment Clause		$14.5		$10.6
Restricted Cash (a)	7.5		5.6
Other	16.4		19.5
Total Prepayments and Other Current Assets		$38.4		$35.7


(a)	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and cash pledged as collateral for U.S. Water Services’ standby letters of credit.

Other Current Liabilities [Table Text Block]



Other Current Liabilities	June 30, 2016		December 31, 2015
Millions
Customer Deposits		$13.4		$15.1
Power Purchase Agreements	23.9		23.3
Other	48.6		47.7
Total Other Current Liabilities		$85.9		$86.1

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities	June 30, 2016		December 31, 2015
Millions
Asset Retirement Obligation		$135.2		$131.4
Power Purchase Agreements	125.9		138.1
Contingent Consideration (a)	37.3		36.6
Other	42.4		42.9
Total Other Non-Current Liabilities		$340.8		$349.0


(a)	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 3. Acquisitions and Note 5. Fair Value.)

Supplemental Statement of Cash Flows Information [Table Text Block]

Supplemental Statement of Cash Flows Information.



Six Months Ended June 30,	2016		2015
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$32.9		$30.0
Cash Paid During the Period for Income Taxes		$0.4		$1.0
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(24.4)		$(25.5)
Capitalized Asset Retirement Costs		$2.3		$7.8
AFUDC–Equity		$1.2		$1.6
Contingent Consideration	—			$35.7

Acquisitions (Table)

6 Months Ended

Jun. 30, 2016

U.S. Water Services [Member]

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
Intangible Assets (c)	83.0
Goodwill (d)	122.9
Other Non-Current Assets	0.2
Total Assets Acquired		$253.1
Liabilities Assumed
Current Liabilities		$19.2
Non-Current Liabilities	31.6
Total Liabilities Assumed		$50.8
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 were 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 was 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 standby letters of credit.


(c)	Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 4. Goodwill and Intangible Assets.)


(d)	For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill.

Chanarambie/Viking [Member]

Schedule of Business Acquisitions [Table Text Block]



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 PPAs.

Armenia Mountain [Member]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Current Assets (a)	$9.0
Property, Plant and Equipment	156.2
Other Non-Current Assets (b)	14.4
Total Assets Acquired		$179.6
Liabilities Assumed
Current Liabilities		$2.9
Long-Term Debt Due Within One Year	5.9
Long-Term Debt	55.0
Other Non-Current Liabilities	4.7
Total Liabilities Assumed	$68.5
Net Identifiable Assets Acquired		$111.1


(a)	Included in Current Assets was $1.0 million related to the current portion of PPAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.


(b)	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PPAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements, and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

A and W Technologies [Member]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Current Assets	$1.0
Property, Plant and Equipment	0.1
Intangible Assets (a)	3.9
Goodwill (b)	4.4
Total Assets Acquired		$9.4
Liabilities Assumed
Current Liabilities		$0.1
Total Liabilities Assumed	$0.1
Net Identifiable Assets Acquired		$9.3


(a)	Intangible Assets include customer relationships and non-compete agreements. (See Note 4. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill.

Goodwill and Intangible Assets (Tables)

6 Months Ended

Jun. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets [Table Text Block]

Balances of intangible assets, net, excluding goodwill as of June 30, 2016, are as follows:



	December 31, 2015		Amortization	June 30, 2016
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	$60.8		$(2.1)		$58.7
Developed Technology and Other (a)	7.2		(0.4)	6.8
Total Definite-Lived Intangible Assets	68.0		(2.5)	65.5
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		n/a	16.6
Total Intangible Assets		$84.6	$(2.5)		$82.1


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

Fair Value (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of June 30, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.4	—		—			$7.4
Available-for-sale – Corporate Debt Securities	—			$11.0	—		11.0
Cash Equivalents	2.3		—		—		2.3
Total Fair Value of Assets		$9.7		$11.0	—			$20.7

Liabilities (b)
Deferred Compensation	—			$15.9	—			$15.9
U.S. Water Services Contingent Consideration	—		—			$37.3	37.3
Total Fair Value of Liabilities	—			$15.9		$37.3		$53.2
Total Net Fair Value of Assets (Liabilities)		$9.7	$(4.9)		$(37.3)		$(32.5)


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


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



	Fair Value as of December 31, 2015
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.6	—		—			$7.6
Available-for-sale – Corporate Debt Securities	—			$10.9	—		10.9
Cash Equivalents	2.0		—		—		2.0
Total Fair Value of Assets		$9.6		$10.9	—			$20.5

Liabilities (b)
Deferred Compensation	—			$16.1	—			$16.1
U.S. Water Services Contingent Consideration	—		—			$36.6	36.6
Total Fair Value of Liabilities	—			$16.1		$36.6		$52.7
Total Net Fair Value of Assets (Liabilities)		$9.6	$(5.2)		$(36.6)		$(32.2)


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


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

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
June 30, 2016	$1,575.2	$1,647.6
December 31, 2015	$1,605.0	$1,676.0

Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	June 30, 2016		December 31, 2015
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$14.5		$10.6
Total Current Regulatory Assets	14.5		10.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	215.0		219.3
Income Taxes (c)	64.7		64.2
Cost Recovery Riders (d)	47.2		58.0
Asset Retirement Obligations (e)	23.5		21.6
PPACA Income Tax Deferral	5.0		5.0
Other	3.7		3.9
Total Non-Current Regulatory Assets	359.1		372.0
Total Regulatory Assets		$373.6		$382.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$57.0		$58.0
Plant Removal Obligations	14.4		22.1
Income Taxes (c)	5.4		6.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	—		0.9
Other	17.8		17.9
Total Non-Current Regulatory Liabilities		$94.6		$105.0


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

(b)


(c)	These assets and liabilities are offsets to deferred income taxes recognized on certain regulatory temporary differences, which will reverse over the remaining lives of those temporary differences.

(d)


(e)	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.


(f)	Wholesale and Retail Contra AFUDC represents the regulatory offset to AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.

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

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Schedule of Short-Term and Long-Term Debt [Table Text Block]

The following tables present ALLETE’s short-term and long-term debt as of June 30, 2016 and December 31, 2015.



June 30, 2016	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt (a)		$66.0	$(0.6)		$65.4
Long-Term Debt	1,510.1		(11.2)	1,498.9
Total Debt		$1,576.1	$(11.8)		$1,564.3


(a)	Consisted of long-term debt due within one year and notes payable.



December 31, 2015	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt (a)		$37.9	$(0.6)		$37.3
Long-Term Debt	1,568.7		(12.0)	1,556.7
Total Debt		$1,606.6	$(12.6)		$1,594.0


(a)	Consisted of long-term debt due within one year and notes payable.

Income Tax Expense (Tables)

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Millions
Current Tax Expense (a)
Federal	—			—			—			—
State		$0.1		$0.2				$0.2		$0.3
Total Current Tax Expense		$0.1		$0.2				$0.2		$0.3
Deferred Tax Expense
Federal	$2.1				$3.9		$6.7				$8.7
State	2.7			2.5			7.5			4.0
Investment Tax Credit Amortization	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Total Deferred Tax Expense	$4.6				$6.2		$13.8				$12.3
Total Income Tax Expense	$4.7				$6.4		$14.0				$12.6


(a)	For the six months ended June 30, 2016 and 2015, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

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
Six Months Ended June 30	2016			2015
Millions
Income Before Non-Controlling Interest and Income Taxes		$85.2			$75.0
Statutory Federal Income Tax Rate	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$29.8			$26.3
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	5.0			2.8
Production Tax Credits	(20.5		)	(20.8		)
Regulatory Differences for Utility Plant	(0.1		)	(0.4		)
Other	(0.2		)	4.7
Total Income Tax Expense		$14.0			$12.6

Earnings Per Share and Common Stock (Tables)

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

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



			2016					2015
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Quarter ended June 30,
Net Income Attributable to ALLETE		$24.8			$24.8		$22.5			$22.5
Average Common Shares	49.3		0.2	49.5		48.6		0.1	48.7
Earnings Per Share		$0.50			$0.50		$0.46			$0.46
Six Months Ended June 30,
Net Income Attributable to ALLETE		$70.7			$70.7		$62.4			$62.4
Average Common Shares	49.2		0.1	49.3		47.7		0.1	47.8
Earnings Per Share		$1.44			$1.43		$1.31			$1.30

Pension and Other Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

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



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2016			2015			2016			2015
Millions
Quarter Ended June 30,
Service Cost		$2.1			$2.5			$1.0			$1.1
Interest Cost	8.1			7.4			1.8			1.8
Expected Return on Plan Assets	(10.7		)	(10.1		)	(2.8		)	(2.8		)
Amortization of Prior Service Costs (Credits)	—			0.1			(0.8		)	(0.7		)
Amortization of Net Loss	2.5			4.5			0.1			0.1
Net Periodic Benefit Expense (Income)		$2.0			$4.4		$(0.7)			$(0.5)

Six Months Ended June 30,
Service Cost		$4.1			$5.0			$2.0			$2.2
Interest Cost	16.2			14.9			3.7			3.6
Expected Return on Plan Assets	(21.3		)	(20.3		)	(5.6		)	(5.5		)
Amortization of Prior Service Costs (Credits)	—			0.1			(1.5		)	(1.5		)
Amortization of Net Loss	4.9			9.0			0.1			0.2
Net Periodic Benefit Expense (Income)		$3.9			$8.7		$(1.3)			$(1.0)

Business Segments (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Business Segments [Table Text Block]



	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Millions
Operating Revenue
Regulated Operations	$234.9			$230.0			$487.2			$492.8

Energy Infrastructure and Related Services
ALLETE Clean Energy	18.8			34.0			42.4			46.4
U.S. Water Services	34.3			34.4			66.7			49.9

Corporate and Other	26.8			24.9			52.3			54.2
Total Operating Revenue		$314.8			$323.3			$648.6			$643.3
Net Income (Loss) Attributable to ALLETE
Regulated Operations (a)		$22.6			$23.3			$65.0			$64.3

Energy Infrastructure and Related Services
ALLETE Clean Energy	2.6			3.0			8.7			5.5
U.S. Water Services	1.0			0.6			0.5			0.5

Corporate and Other (a)	(1.4		)	(4.4		)	(3.5		)	(7.9		)
Total Net Income Attributable to ALLETE		$24.8			$22.5			$70.7			$62.4


(a)	In 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries which is 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, 2015.



	June 30, 2016		December 31, 2015
Millions
Assets
Regulated Operations (a)	$3,823.4		$3,853.1

Energy Infrastructure and Related Services
ALLETE Clean Energy (a)	489.5		501.5
U.S. Water Services	258.2		258.3

Corporate and Other	286.5		281.6
Total Assets (a)		$4,857.6		$4,894.5


(a)	As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been revised to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)

Operations and Significant Accounting Policies (Details) - USD ($)
$ in Millions

Jun. 30, 2016

Dec. 31, 2015

Inventories [Abstract]

Fuel

^[1]

$ 49.2

$ 58.1

Materials and Supplies

49.8

49.1

Raw Materials

2.8

2.7

Work in Progress

0.6

0.0

Finished Goods

8.3

7.5

Reserve for Obsolescence

(0.3)

Total Inventories

110.4

117.1

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

14.5

10.6

Restricted Cash

^[2]

7.5

5.6

Total Prepayments and Other Current Assets

16.4

19.5

38.4

35.7

Other Non-Current Assets [Abstract]

Restricted Cash

8.2

8.1

Contract Payment

31.0

Other Current Liabilites [Abstract]

Customer Deposits

13.4

15.1

Power Purchase Agreements

23.9

23.3

Total Other Current Liabilities

48.6

47.7

85.9

86.1

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

135.2

131.4

Power Purchase Agreements

125.9

138.1

Contingent Consideration

^[3]

37.3

36.6

Total Other Non-Current Liabilities

42.4

42.9

$ 340.8

$ 349.0

[1]	Fuel consists primarily of coal inventory at Minnesota Power.
[2]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and cash pledged as collateral for U.S. Water Services’ standby letters of credit.
[3]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 3. Acquisitions and Note 5. Fair Value.)

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flows Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$ 32.9	$ 30.0
Cash Paid During the Period for Income Taxes	0.4	1.0
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	(24.4)	(25.5)
Capitalized Asset Retirement Costs	2.3	7.8
AFUDC–Equity	1.2	1.6
Contingent Consideration	$ 0.0	$ 35.7

Operations and Significant Accounting Policies - New Accounting Standards (Details) - Accounting Standards Update 2015-03 [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Total Assets [Member]
New Accounting Standards [Line Items]
Effect of the Adoption	$ (12.6)
Total Liabilities [Member]
New Accounting Standards [Line Items]
Effect of the Adoption	$ (12.6)

Investments (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2016

Dec. 31, 2015

Available-for-sale Securities

ALLETE Properties

$ 47.8

$ 50.1

18.4

^[1]

18.4

^[1]

18.5

2.3

2.0

Available-for-sale Securities Corporate Debt Securities, Maturities [Abstract]

3.8

4.0

Total Other Investments

72.3

$ 74.6

One Year or Less

0.2

One Year to Less Than Three Years

2.5

Three Years to Less Than Five Years

5.0

Five or More Years

3.3

Impairment of Land Inventory

$ 0.0

[1]	As of June 30, 2016, 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 $2.5 million, in three years to less than five years was $5.0 million, and in five or more years was $3.3 million.

Acquisitions (Details)	6 Months Ended
Acquisitions (Details)	Jun. 30, 2016	Jun. 30, 2015
Business Combinations [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 - Acquisition of Non-Controlling Interest (Details) $ in Millions	Apr. 15, 2016 USD ($)
ALLETE Clean Energy [Member]
Non-Controlling Interest [Line Items]
Payment to Acquire Non-Controlling Interest	$ 8.0

Acquisitions - U.S. Water Services (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

11 Months Ended

Feb. 28, 2015

Mar. 31, 2015

Jun. 30, 2016

Dec. 31, 2015

$ 130.6

U.S. Water Services [Member]

^[1]

$ 7.5

$ 5.6

U.S. Water Services

Total Consideration

$ 202.3

Percent of Results of Operations Reflected in Income Statement

166.6

Contingent Consideration

$ 35.7

100.00%

100.00%

Cash and Cash Equivalents

$ 0.9

Accounts Receivable

16.8

Inventories

^[2]

13.4

Other Current Assets

^[3]

5.3

10.6

Intangible Assets

^[4]

83.0

^[5]

122.9

0.2

253.1

19.2

Non-Current Liabilities

31.6

50.8

Fair Value Adjustments for Work in Process and Finished Goods

202.3

2.7

Fair Value of Sales Backlog

1.6

2.1

Acquisition Related Costs

$ 2.9

$ 3.0

[1]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and cash pledged as collateral for U.S. Water Services’ standby letters of credit.
[2]	Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of Sales within one year from the acquisition date.
[3]	Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog was 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 standby letters of credit.
[4]	Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 4. Goodwill and Intangible Assets.)
[5]	For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill.

Acquisitions - Chanarambie/Viking (Details)
$ in Millions

1 Months Ended

3 Months Ended

Apr. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Jun. 30, 2016

USD ($)

Dec. 31, 2015

USD ($)

Power Purchase Agreements - Non-Current Liability

$ 125.9

$ 138.1

Power Purchase Agreements - Current Liability

130.6

$ 23.9

$ 23.3

Chanarambie/Viking [Member]

100.00%

Chanarambie/Viking

$ 48.0

97.5

Current Assets

$ 4.8

103.0

^[1]

1.0

108.8

Power Purchase Agreements - Non-Current Liability

^[2]

6.7

49.0

Non-Current Liabilities

5.1

60.8

48.0

0.3

Power Purchase Agreements - Current Liability

0.0

$ 5.9

Acquisition Related Costs

$ 0.2

Chanarambie/Viking [Member] | Chanarambie/Viking PPA (expires 2018) [Member]

Chanarambie/Viking [Member] | Chanarambie/Viking PPA (expires 2023) [Member]

85.5

[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 PPAs.

Acquisitions - Armenia Mountain (Details)
$ in Millions

1 Months Ended

6 Months Ended

Jul. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2016

USD ($)

Dec. 31, 2015

USD ($)

Restricted Cash - Non-Current

^[1]

$ 7.5

$ 5.6

$ 8.2

$ 8.1

Armenia Mountain [Member]

100.00%

Armenia Mountain

$ 111.1

Current Assets

^[2]

9.0

156.2

^[3]

14.4

179.6

Long-Term Debt Due Within One Year

2.9

5.9

Long-Term Debt

55.0

Other Non-Current Liabilities

4.7

68.5

Power Purchase Agreements - Current Asset

111.1

1.0

Power Purchase Agreements - Non-Current Asset

6.0

8.2

Restricted Cash - Non-Current

6.1

Acquisition Related Costs

$ 0.0

$ 1.6

Armenia Mountain [Member] | Armenia Mountain PPAs (expire 2024) [Member]

100.5

[1]	Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and cash pledged as collateral for U.S. Water Services’ standby letters of credit.
[2]	Included in Current Assets was $1.0 million related to the current portion of PPAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.
[3]	Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PPAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements, and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisitions - A and W Technologies (Details) - USD ($)
$ in Millions

1 Months Ended

Nov. 30, 2015

Jun. 30, 2016

Dec. 31, 2015

A and W Technologies [Member]

$ 130.6

100.00%

A and W Technologies, Inc.

Total Consideration

$ 9.3

Payment Due in April 2017

8.3

1.0

Current Assets

1.0

0.1

Intangible Assets

^[1]

3.9

^[2]

4.4

9.4

0.1

0.1

9.3

Definite-Lived Intangible Assets [Roll Forward]

$ 4.4

[1]	Intangible Assets include customer relationships and non-compete agreements. (See Note 4. Goodwill and Intangible Assets.)
[2]	For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill.

Goodwill and Intangible Assets - Goodwill (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 130.6	$ 130.6
Changes to Goodwill	$ 0.0

Goodwill and Intangible Assets - Intangible Assets (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2016

Dec. 31, 2015

$ 68.0

Amortization

(2.5)

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

65.5

Accumulated Amortization

6.6

$ 4.1

2.6

5.0

4.7

4.4

4.2

44.6

Intangible Assets [Abstract]

Total Intangible Assets

82.1

$ 84.6

Total Intangible Assets, Amortization

$ (2.5)

Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Trademarks and Trade Names [Member]

20 years

Indefinite-Lived Intangible Assets [Roll Forward]

$ 16.6

Customer Relationships [Member]

16.6

Definite-Lived Intangible Assets [Roll Forward]

60.8

Amortization

(2.1)

$ 58.7

Total Intangible Assets, Amortization

22 years

Intangible Assets [Abstract]

$ (2.1)

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

^[1]

7.2

Amortization

^[1]

(0.4)

Total Intangible Assets, Amortization

^[1]

6.8

Intangible Assets [Abstract]

^[1]

$ (0.4)

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

Definite-Lived Intangible Assets [Roll Forward]

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

3 years

Definite-Lived Intangible Assets [Roll Forward]

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

13 years

Definite-Lived Intangible Assets [Roll Forward]

8 years

[1]	Developed Technology and Other includes patents, non-compete agreements and land easements.

Fair Value - Recurring Fair Value Measures (Details) - USD ($)
$ in Millions

6 Months Ended

12 Months Ended

Jun. 30, 2016

Dec. 31, 2015

$ 2.3

$ 2.0

Recurring Fair Value Measurements [Member]

^[1]

37.3

36.6

7.4

^[2]

7.6

^[3]

11.0

^[2]

10.9

^[3]

2.3

^[2]

2.0

^[3]

20.7

20.5

15.9

^[4]

16.1

^[5]

37.3

^[4]

36.6

^[5]

53.2

52.7

Fair Value Hierarchy Transfers, All Levels

(32.5)

(32.2)

0.0

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

7.4

^[2]

7.6

^[3]

0.0

^[2]

0.0

^[3]

2.3

^[2]

2.0

^[3]

9.7

9.6

0.0

^[4]

0.0

^[5]

0.0

^[4]

0.0

^[5]

0.0

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

9.7

9.6

0.0

^[2]

0.0

^[3]

11.0

^[2]

10.9

^[3]

0.0

^[2]

0.0

^[3]

11.0

10.9

15.9

^[4]

16.1

^[5]

0.0

^[4]

0.0

^[5]

15.9

16.1

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

(4.9)

(5.2)

0.0

^[2]

0.0

^[3]

0.0

^[2]

0.0

^[3]

0.0

^[2]

0.0

^[3]

0.0

0.0

^[4]

0.0

^[5]

37.3

^[4]

36.6

^[5]

37.3

36.6

$ (37.3)

$ (36.6)

[1]	Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 3. Acquisitions and Note 5. Fair Value.)
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Investments on the Consolidated Balance Sheet.
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[5]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

Fair Value - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,575.2	$ 1,605.0
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,647.6	$ 1,676.0

Fair Value - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Nonrecurring Fair Value Measurements [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Abstract]
Indicators of Impairment	$ 0.0	$ 0.0

Regulatory Matters - Utility Rates (Details) $ in Millions				6 Months Ended
Regulatory Matters - Utility Rates (Details) $ in Millions	Jun. 28, 2016 USD ($)	Jan. 01, 2013	Jun. 01, 2011	Jun. 30, 2016 USD ($) Customers Years MW	Jun. 30, 2015 USD ($)
Minnesota Power [Member] \| Bison Wind Energy Center [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW) \| MW				497
PSCW [Member] \| 2012 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity		10.90%
PSCW [Member] \| 2016 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)	3.10%
Requested Return on Equity	10.90%
Requested Equity Capital Structure	55.00%
Requested Debt Capital Structure	45.00%
Annual Additional Revenue Generated from Overall Requested Rate Increase \| $	$ 2.7
Electric Rates [Member] \| MPUC [Member] \| 2010 Minnesota Rate Case [Member] \| Minnesota Power [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity			10.38%
Approved Equity Ratio			54.29%
Electric Rates [Member] \| MPUC [Member] \| Minnesota Cost Recovery Riders [Member] \| Minnesota Power [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Revenue from Cost Recovery Riders \| $				$ 48.9	$ 44.9
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Minnesota Power [Member] \| Retail [Member]
Regulatory Matters [Line Items]
North Dakota Investment Tax Credits \| $				8.0
Electric Rates [Member] \| MPUC [Member] \| Annual Automatic Adjustment of Charges [Member] \| Minnesota Power [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Retail Fuel Cost Recovery Collected but Subject to Refund \| $				$ 350.0
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers				16
Length of Notice Required to Terminate Contract (Years) \| Years				3
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire December 2024) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers				14
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire December 2024) [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Change in Annual Capacity Charge Per Contract - Percentage				2.00%
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire December 2024) [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Change in Annual Capacity Charge Per Contract - Percentage				(1.00%)
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contract (Termination Effective June 2019) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers				1
Average Monthly Demand (MW) \| MW				29
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contract (Cost-Based Formula Methodology for Entire Term) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers				3
Electric Rates [Member] \| PSCW [Member] \| 2016 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)	3.50%
Natural Gas Rates [Member] \| PSCW [Member] \| 2016 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)	(1.30%)
Water Rates [Member] \| PSCW [Member] \| 2016 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)	7.80%

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - Integrated Resource Plan [Member] - Natural Gas-Fired [Member] - Minnesota Power [Member]	Jun. 30, 2016 MW
Minimum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	200
Maximum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	300

Regulatory Matters - Great Northern Transmission Line (GNTL) (Details) - Great Northern Transmission Line [Member] - Transmission Line [Member]	Jun. 30, 2016 kV Miles
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
MPUC [Member] \| Great Northern Transmission Line Route Permit [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500

Regulatory Matters - Conservation Improvement Program (CIP) (Details) - MPUC [Member] - USD ($) $ in Millions	Jul. 14, 2016	Jun. 30, 2016
Regulatory Matters [Line Items]
CIP Spend Requirement		1.50%
Subsequent Event [Member] \| CIP Annual Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
CIP Financial Incentive	$ 7.5

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Jun. 30, 2016	Jan. 06, 2015
Return on Equity Complaint 1 [Member]
Loss Contingencies [Line Items]
Requested Return on Equity Filed with the FERC by Third Party	9.15%
Proposed Return on Equity by Federal Administrative Law Judge	10.32%
Return on Equity Complaint 2 [Member]
Loss Contingencies [Line Items]
Requested Return on Equity Filed with the FERC by Third Party	8.67%
Proposed Return on Equity by Federal Administrative Law Judge	9.70%
Incentive Adder [Member]
Loss Contingencies [Line Items]
FERC Approved Incentive Adder for Participation in Regional Transmission Organization		50

Regulatory Matters - Minnesota Solar Energy Standard (Details) - MPUC [Member]	Jun. 30, 2016 Projects MW
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Overall Mandate Percentage	1.50%
Minimum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Small Scale Solar Mandate Percentage	10.00%
Maximum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.02
Minnesota Solar Energy Standard [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Number of Projects \| Projects	2
Solar Energy Standard Mandate - Percentage of Overall Mandate Expected to be Met with Current Filings or Projects	33.00%
Minnesota Solar Energy Standard - Camp Ripley Project [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	10
Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	1
Minnesota Solar Energy Standard - Community Solar Garden Project - Owned and Operated [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	0.04

Regulatory Matters - Regulatory Assets and Liabilities (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2016

Dec. 31, 2015

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

Current Regulatory Assets

$ 14.5

$ 10.6

359.1

372.0

Total Regulatory Assets

373.6

382.6

Wholesale and Retail Contra AFUDC [Member]

94.6

105.0

Plant Removal Obligations [Member]

^[1]

57.0

58.0

14.4

22.1

Income Taxes [Member]

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

^[2]

5.4

6.1

Deferred Fuel Adjustment Clause [Member]

^[3]

0.0

0.9

Current Regulatory Assets

^[4]

14.5

10.6

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

^[3]

215.0

219.3

Income Taxes [Member]

Cost Recovery Riders [Member]

^[2]

64.7

64.2

Asset Retirement Obligations [Member]

^[5]

47.2

58.0

PPACA Income Tax Deferral [Member]

^[6]

23.5

21.6

5.0

3.7

3.9

Short-Term Debt - Principal

$ 17.8

$ 17.9

[1]	Wholesale and Retail Contra AFUDC represents the regulatory offset to AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.
[2]	These assets and liabilities are offsets to deferred income taxes recognized on certain regulatory temporary differences, which will reverse over the remaining lives of those temporary differences.
[3]	Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)
[4]	Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
[5]	The cost recovery rider regulatory assets are revenues not yet collected from our customers 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. The cost recovery rider regulatory assets as of June 30, 2016, will be recovered over the next two years.
[6]	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.

Investment in ATC (Details) $ in Millions		3 Months Ended		6 Months Ended
Investment in ATC (Details) $ in Millions	Jul. 29, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2015				$ 124.5
Cash Investments				1.6	$ 0.8
Equity in ATC Earnings		$ 4.1	$ 4.7	8.9	$ 8.6
Equity Investment Balance as of June 30, 2016		$ 129.0		$ 129.0
ATC [Member]
Investment in ATC [Line Items]
Ownership Percentage		8.00%		8.00%
Expected Additional Investment in 2016		$ 2.7		$ 2.7
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2015				124.5
Cash Investments				1.6
Equity in ATC Earnings				8.9
Distributed ATC Earnings				(6.0)
Equity Investment Balance as of June 30, 2016		$ 129.0		$ 129.0
Authorized Return on Equity		12.20%		12.20%
ATC [Member] \| Subsequent Event [Member]
ALLETE's Investment in ATC [Roll Forward]
Cash Investments	$ 1.9
Sensitivity Analysis [Member] \| ATC [Member]
ALLETE's Investment in ATC [Roll Forward]
Basis Point Reduction on Approved Rate of Return on Common Equity		50		50
After-tax [Member] \| Sensitivity Analysis [Member] \| ATC [Member]
ALLETE's Investment in ATC [Roll Forward]
Annual Effect on Future Equity Earnings in ATC				$ 0.5
Pre-tax [Member] \| Sensitivity Analysis [Member] \| ATC [Member]
ALLETE's Investment in ATC [Roll Forward]
Annual Effect on Future Equity Earnings in ATC				$ 0.9

Short-Term and Long-Term Debt (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2016

Dec. 31, 2015

Debt Disclosure [Abstract]

$ 66.0

^[1]

$ 37.9

^[2]

Short-Term Debt - Unamortized Debt Issuance Costs

(0.6)

^[1]

(0.6)

^[2]

Short-Term Debt - Total

65.4

^[1]

37.3

^[2]

Long-term Debt - Principal

1,510.1

1,568.7

Long-Term Debt - Unamortized Debt Issuance Costs

(11.2)

(12.0)

Long-Term Debt - Total

1,498.9

1,556.7

Total Debt - Principal

1,576.1

1,606.6

Total Debt - Unamortized Debt Issuance Costs

(11.8)

(12.6)

Total Debt - Total

1,564.3

$ 1,594.0

Proceeds from Issuance of Long-Term Debt

$ 0.0

[1]	Consisted of long-term debt due within one year and notes payable.
[2]	Consisted of long-term debt due within one year and notes payable.

Short-Term and Long-Term Debt - Financial Covenants (Details)	Jun. 30, 2016
Debt Instrument [Line Items]
Actual Indebtedness to Total Capitalization Ratio	0.46
Maximum [Member]
Debt Instrument [Line Items]
Allowed Indebtedness to Total Capitalization Ratio	0.65

Income Tax Expense (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Dec. 31, 2015

Current Tax Expense [Abstract]

Federal

^[1]

$ 0.0

State

^[1]

0.1

0.2

0.3

Total Current Tax Expense

0.1

0.2

0.3

Deferred Tax Expense [Abstract]

Federal

2.1

3.9

6.7

8.7

State

2.7

2.5

7.5

4.0

Investment Tax Credit Amortization

(0.2)

(0.4)

Total Deferred Tax Expense

4.6

6.2

13.8

12.3

Total Income Tax Expense

4.7

6.4

14.0

12.6

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

Income Before Non-Controlling Interest and Income Taxes

29.5

28.7

$ 85.2

$ 75.0

Statutory Federal Income Tax Rate

35.00%

Income Taxes Computed at 35 percent Statutory Federal Rate

$ 29.8

$ 26.3

Increase (Decrease) in Tax [Abstract]

State Income Taxes – Net of Federal Income Tax Benefit

5.0

2.8

Production Tax Credits

(20.5)

(20.8)

Regulatory Differences for Utility Plant

(0.1)

(0.4)

Gross Unrecognized Tax Benefits

(0.2)

4.7

Total Income Tax Expense

4.7

$ 6.4

$ 14.0

$ 12.6

Effective Tax Rate

16.40%

16.80%

Uncertain Tax Positions [Abstract]

2.2

$ 2.2

$ 2.4

Unrecognized Tax Benefits That Would Favorably Impact Effective Income Tax Rate

$ 0.5

[1]

For the six months ended June 30, 2016 and 2015, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

Earnings Per Share and Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Antidilutive Shares Excluded from Diluted Earnings Per Share Computation			0.0	0.0
Earnings Per Share - Basic [Abstract]
Net Income Attributable to ALLETE	$ 24.8	$ 22.5	$ 70.7	$ 62.4
Average Common Shares	49.3	48.6	49.2	47.7
Earnings Per Share	$ 0.50	$ 0.46	$ 1.44	$ 1.31
Earnings Per Share - Diluted [Abstract]
Net Income Attributable to ALLETE	$ 24.8	$ 22.5	$ 70.7	$ 62.4
Average Common Shares	49.5	48.7	49.3	47.8
Earnings Per Share	$ 0.50	$ 0.46	$ 1.43	$ 1.30
Dilutive Securities (Shares)	0.2	0.1	0.1	0.1

Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension [Member]
Components of Net Periodic Benefit Expense (Income) [Abstract]
Service Cost	$ 2.1	$ 2.5	$ 4.1	$ 5.0
Interest Cost	8.1	7.4	16.2	14.9
Expected Return on Plan Assets	(10.7)	(10.1)	(21.3)	(20.3)
Amortization of Prior Service Costs (Credits)	0.0	0.1	0.0	0.1
Amortization of Net Loss	2.5	4.5	4.9	9.0
Net Periodic Benefit Expense (Income)	2.0	4.4	3.9	8.7
Contributions			0.0	0.0
Expected Future Contributions in 2016			2.0
Other Postretirement [Member]
Components of Net Periodic Benefit Expense (Income) [Abstract]
Service Cost	1.0	1.1	2.0	2.2
Interest Cost	1.8	1.8	3.7	3.6
Expected Return on Plan Assets	(2.8)	(2.8)	(5.6)	(5.5)
Amortization of Prior Service Costs (Credits)	(0.8)	(0.7)	(1.5)	(1.5)
Amortization of Net Loss	0.1	0.1	0.1	0.2
Net Periodic Benefit Expense (Income)	$ (0.7)	$ (0.5)	(1.3)	(1.0)
Contributions			0.0	$ 0.0
Expected Future Contributions in 2016			$ 0.0

Commitments, Guarantees and Contingencies - Power Purchase Agreements (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) MW	Jun. 30, 2015 USD ($)
Square Butte [Member] \| Square Butte PPA [Member]
Power Purchase Agreements [Line Items]
PPA Counterparty Debt Outstanding \| $	$ 361.9
Cost of Power Purchased \| $	37.7	$ 39.5
Pro Rata Share of Interest Expense \| $	$ 4.8	$ 5.0
Square Butte [Member] \| Square Butte PPA [Member] \| Square Butte Coal-fired Unit [Member]
Power Purchase Agreements [Line Items]
Generating Capacity (MW)	455
Output Entitlement	50.00%
Minnkota Power [Member] \| Square Butte Coal-fired Unit [Member] \| Minnkota Power Sales Agreement [Member]
Power Purchase Agreements [Line Items]
Output Entitlement	28.00%	28.00%
Silver Bay Power [Member] \| Silver Bay Power Sales Agreement through 2031 (Years 2016-2019) [Member] \| Minimum [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	50
Silver Bay Power [Member] \| Silver Bay Power Sales Agreement through 2031 (Years 2020-2031) [Member]
Power Purchase Agreements [Line Items]
Output Being Sold (MW)	90
Silver Bay Power [Member] \| Silver Bay Power Self-Generation [Member]
Power Purchase Agreements [Line Items]
Generating Capacity (MW)	90
Shell Energy [Member] \| Shell Energy PPA [Member]
Power Purchase Agreements [Line Items]
Output Being Purchased (MW)	50

Commitments, Guarantees and Contingencies - Coal, Rail and Shipping Contracts (Details) - Coal Supply and Transportation Agreements [Member] $ in Millions	Jun. 30, 2016 USD ($)
Coal, Rail and Shipping Contracts [Line Items]
Minimum Annual Payment Obligation for Remainder of 2016	$ 17.7
Minimum Annual Payment Obligation in 2017	27.9
Minimum Annual Payment Obligation in 2018	27.0
Minimum Annual Payment Obligation in 2019	1.8
Minimum Annual Payment Obligation in 2020	0.0
Minimum Annual Payment Obligation Thereafter	$ 0.0

Commitments, Guarantees and Contingencies - Leasing Agreements (Details) $ in Millions	Jun. 30, 2016 USD ($)
Leasing Agreements [Line Items]
Minimum Lease Payments Due in 2016	$ 14.0
Minimum Lease Payments Due in 2017	12.6
Minimum Lease Payments Due in 2018	11.1
Minimum Lease Payments Due in 2019	9.9
Minimum Lease Payments Due in 2020	6.9
Minimum Lease Payments Thereafter	23.2
BNI Coal Dragline Lease [Member]
Leasing Agreements [Line Items]
Minimum Lease Payments Due in 2016	2.8
Minimum Lease Payments Due in 2017	2.8
Minimum Lease Payments Due in 2018	2.8
Minimum Lease Payments Due in 2019	2.8
Minimum Lease Payments Due in 2020	2.8
Minimum Lease Payments Thereafter	19.6
Termination Fee	$ 3.0

Commitments, Guarantees and Contingencies - Transmission (Details) - Great Northern Transmission Line [Member] - Transmission Line [Member] $ in Millions	Jun. 30, 2016 USD ($) kV Miles
Transmission [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Minimum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	$ 560
Maximum [Member]
Transmission [Line Items]
Estimated Capital Expenditures	$ 710

Commitments, Guarantees and Contingencies - Environmental Matters (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) MW
Ozone NAAQS [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	$ 0.0
Minimum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	65.0
Maximum [Member] \| Clean Water Act - Aquatic Organisms [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	15.0
Maximum [Member] \| Coal Combustion Residuals [Member]
Environmental Matters [Line Items]
Estimated Environmental Compliance Costs	$ 100.0
NOV Consent Decree [Member]
Environmental Matters [Line Items]
Additional Wind Generating Capacity (MW) \| MW	200
NOV Consent Decree [Member] \| Minimum [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures	$ 20.0
NOV Consent Decree [Member] \| Maximum [Member]
Environmental Matters [Line Items]
Estimated Capital Expenditures	$ 40.0

Commitments, Guarantees and Contingencies - Other Matters (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
ALLETE Clean Energy [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 14.6
U.S. Water Services [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.8
BNI Energy Reclamation Liability [Member]
Guarantor Obligations [Line Items]
Estimated Obligation	47.5
BNI Energy Reclamation Liability [Member] \| Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	0.6
BNI Energy 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	6.1
ALLETE Properties Development and Maintenance Obligations [Member] \| Surety Bonds and Letters of Credit [Member]
Guarantor Obligations [Line Items]
Collateral	$ 10.1
Town Center Community Development District Obligations [Member]
Guarantor Obligations [Line Items]
Ownership Percentage of Benefited Property	72.00%	72.00%
Annual Assessment	$ 1.4
Palm Coast Park Community Development District Obligations [Member]
Guarantor Obligations [Line Items]
Ownership Percentage of Benefited Property	92.00%	92.00%
Annual Assessment	$ 2.1

Business Segments (Details)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2016

USD ($)

Jun. 30, 2015

USD ($)

Jun. 30, 2016

USD ($)

Segments

Jun. 30, 2015

USD ($)

Dec. 31, 2015

USD ($)

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

Number of Reportable Segments | Segments

$ 314.8

$ 323.3

$ 648.6

$ 643.3

24.8

22.5

70.7

62.4

Regulated Operations [Member]

^[1]

4,857.6

$ 4,857.6

$ 4,894.5

Number of Operating Segments | Segments

234.9

230.0

$ 487.2

492.8

^[2]

22.6

23.3

65.0

64.3

ALLETE Clean Energy [Member]

^[1]

3,823.4

3,853.1

18.8

34.0

42.4

46.4

2.6

3.0

8.7

5.5

U.S. Water Services [Member]

^[1]

489.5

501.5

34.3

34.4

66.7

49.9

1.0

0.6

0.5

Corporate and Other [Member]

$ 258.2

258.3

Number of Operating Segments | Segments

Land in Minnesota (Acres) | a

5,000

$ 26.8

24.9

$ 52.3

54.2

^[2]

(1.4)

$ (4.4)

(3.5)

$ (7.9)