Document and Entity Information Document	6 Months Ended
Document and Entity Information Document	Jun. 30, 2017 shares
Document and Entity Information [Line Items]
Entity Registrant Name	ALLETE INC
Entity Central Index Key	0000066756
Entity Tax Identification Number	410418150
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	50,956,836
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017

Consolidated Balance Sheet - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current Assets [Abstract]
Cash and Cash Equivalents	$ 84.2	$ 27.5
Accounts Receivable (Less Allowance of $2.4 and $3.1)	120.1	122.5
Inventories – Net	103.4	104.2
Prepayments and Other	38.8	40.3
Total Current Assets	346.5	294.5
Property, Plant and Equipment – Net	3,745.6	3,741.2
Regulatory Assets	324.5	330.1
Investment in ATC	143.1	135.6
Other Investments	56.2	55.6
Goodwill and Intangible Assets – Net	210.8	213.4
Other Non-Current Assets	104.8	106.5
Total Assets	4,931.5	4,876.9
Current Liabilities [Abstract]
Accounts Payable	61.0	74.0
Accrued Taxes	39.1	46.5
Accrued Interest	17.5	17.6
Long-Term Debt Due Within One Year	117.7	187.7
Other	70.1	73.7
Total Current Liabilities	305.4	399.5
Long-Term Debt	1,401.4	1,370.4
Deferred Income Taxes	577.0	554.6
Regulatory Liabilities	125.8	125.8
Defined Benefit Pension and Other Postretirement Benefit Plans	195.8	210.9
Other Non-Current Liabilities	309.1	322.7
Total Liabilities	2,914.5	2,983.9
Commitments, Guarantees and Contingencies (Note 13)
Shareholders’ Equity [Abstract]
Common Stock Without Par Value, 80.0 Shares Authorized, 51.0 and 49.6 Shares Issued and Outstanding	1,386.5	1,295.3
Accumulated Other Comprehensive Loss	(27.3)	(28.2)
Retained Earnings	657.8	625.9
Total Shareholders’ Equity	2,017.0	1,893.0
Total Liabilities and Shareholders' Equity	$ 4,931.5	$ 4,876.9

Consolidated Balance Sheet Parentheticals - USD ($) shares in Millions, $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Accounts Receivable [Abstract]
Accounts Receivable, Allowance	$ 2.4	$ 3.1
Common Stock [Abstract]
Common Stock, Par Value	$ 0.00	$ 0.00
Common Stock, Shares Authorized	80.0	80.0
Common Stock, Shares Outstanding	51.0	49.6
Common Stock, Shares Issued	51.0	49.6

Consolidated Statement of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Operating Revenue [Abstract]
Utility	$ 264.9	$ 234.9	$ 546.5	$ 487.2
Non-utility	88.4	79.9	172.4	161.4
Total Operating Revenue	353.3	314.8	718.9	648.6
Operating Expenses [Abstract]
Fuel, Purchased Power and Gas – Utility	93.1	79.0	189.7	158.9
Transmission Services – Utility	17.6	16.1	34.2	32.9
Cost of Sales – Non-utility	38.4	32.5	70.0	62.8
Operating and Maintenance	84.9	82.0	168.2	160.1
Depreciation and Amortization	50.1	48.7	100.6	96.8
Taxes Other than Income Taxes	14.2	14.3	28.6	28.1
Total Operating Expenses	298.3	272.6	591.3	539.6
Operating Income	55.0	42.2	127.6	109.0
Other Income (Expense) [Abstract]
Interest Expense	(16.7)	(17.4)	(33.9)	(34.3)
Equity Earnings in ATC	5.3	4.1	11.4	8.9
Other	0.6	0.6	1.2	1.6
Total Other Expense	(10.8)	(12.7)	(21.3)	(23.8)
Income Before Non-Controlling Interest and Income Taxes	44.2	29.5	106.3	85.2
Income Tax Expense	7.3	4.7	20.4	14.0
Net Income	36.9	24.8	85.9	71.2
Less: Non-Controlling Interest in Subsidiaries	0.0	0.0	0.0	0.5
Net Income Attributable to ALLETE	$ 36.9	$ 24.8	$ 85.9	$ 70.7
Average Shares of Common Stock and Per Share Data [Abstract]
Basic (Shares)	50.9	49.3	50.5	49.2
Diluted (Shares)	51.1	49.5	50.7	49.3
Basic Earnings Per Share of Common Stock	$ 0.73	$ 0.50	$ 1.70	$ 1.44
Diluted Earnings Per Share of Common Stock	0.72	0.50	1.69	1.43
Dividends Per Share of Common Stock	$ 0.535	$ 0.52	$ 1.07	$ 1.04

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Comprehensive Income [Abstract]
Net Income	$ 36.9	$ 24.8	$ 85.9	$ 71.2
Other Comprehensive Income (Loss) [Abstract]
Currency Translation Adjustments	(0.2)	0.0	(0.2)	0.0
Unrealized Gain on Securities Net of Income Tax Expense of $0.2, $0.3, $0.5 and $-	0.4	0.4	0.7	0.0
Defined Benefit Pension and Other Postretirement Benefit Plans Net of Income Tax Expense of $0.2, $0.1, $0.3, and $0.2	0.2	0.1	0.4	0.3
Total Other Comprehensive Income	0.4	0.5	0.9	0.3
Total Comprehensive Income	37.3	25.3	86.8	71.5
Less: Non-Controlling Interest in Subsidiaries	0.0	0.0	0.0	0.5
Total Comprehensive Income Attributable to ALLETE	$ 37.3	$ 25.3	$ 86.8	$ 71.0

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Unrealized Gain on Securities, Income Tax Expense	$ 0.2	$ 0.3	$ 0.5	$ 0.0
Defined Benefit Pension and Other Postretirement Benefit Plans, Income Tax Expense	$ 0.2	$ 0.1	$ 0.3	$ 0.2

Consolidated Statement of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating Activities [Abstract]
Net Income	$ 85.9	$ 71.2
AFUDC – Equity	(0.4)	(1.2)
Income from Equity Investments – Net of Dividends	(2.5)	(2.9)
Change in Fair Value of Contingent Consideration	(0.4)	0.0
Depreciation Expense	97.9	94.2
Amortization of PSAs	(11.8)	(11.1)
Amortization of Other Intangible Assets and Other Assets	5.3	5.0
Deferred Income Tax Expense	20.2	13.8
Share-Based and ESOP Compensation Expense	3.3	2.2
Defined Benefit Pension and Postretirement Benefit Expense	5.0	2.6
Bad Debt Expense	0.0	1.1
Changes in Operating Assets and Liabilities [Abstract]
Accounts Receivable	2.4	6.5
Inventories	0.8	6.7
Prepayments and Other	4.3	(0.8)
Accounts Payable	(12.6)	1.3
Other Current Liabilities	(12.8)	(18.5)
Cash Contributions to Defined Benefit Pension Plans	(1.7)	0.0
Changes in Regulatory and Other Non-Current Assets	6.7	(21.0)
Changes in Regulatory and Other Non-Current Liabilities	(5.2)	(2.9)
Cash from Operating Activities	184.4	146.2
Investing Activities [Abstract]
Proceeds from Sale of Available-for-sale Securities	1.0	1.4
Payments for Purchase of Available-for-sale Securities	(1.6)	(1.2)
Investment in ATC	(5.0)	(1.6)
Changes to Other Investments	1.3	2.1
Additions to Property, Plant and Equipment	(81.1)	(74.8)
Proceeds from Sale of Property, Plant and Equipment	0.7	0.2
Cash for Investing Activities	(84.7)	(73.9)
Financing Activities [Abstract]
Proceeds from Issuance of Common Stock	74.4	15.2
Proceeds from Issuance of Long-Term Debt	86.2	2.2
Changes in Restricted Cash	(1.5)	(2.0)
Changes in Notes Payable	0.0	(0.7)
Repayments of Long-Term Debt	(127.0)	(32.1)
Acquisition of Non-Controlling Interest	0.0	(8.0)
Acquisition-Related Contingent Consideration Payments	(19.7)	(0.7)
Dividends on Common Stock	(54.0)	(51.2)
Other Financing Activities	(1.4)	(0.1)
Cash for Financing Activities	(43.0)	(77.4)
Change in Cash and Cash Equivalents	56.7	(5.1)
Cash and Cash Equivalents at Beginning of Period	27.5	97.0
Cash and Cash Equivalents at End of Period	$ 84.2	$ 91.9

Consolidated Statement of Shareholders' Equity - 6 months ended Jun. 30, 2017 - USD ($) $ in Millions	Total	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Common Stock [Member]
Beginning Balance at Dec. 31, 2016	$ 1,893.0	$ 625.9	$ (28.2)	$ 1,295.3
Comprehensive Income [Abstract]
Net Income	85.9	85.9
Other Comprehensive Income – Net of Tax [Abstract]
Currency Translation Adjustments	(0.2)		(0.2)
Unrealized Gain on Securities	0.7		0.7
Defined Benefit Pension and Other Postretirement Plans	0.4		0.4
Total Comprehensive Income	86.8
Common Stock Issued	91.2			91.2
Dividends Declared	(54.0)	(54.0)
Ending Balance at Jun. 30, 2017	$ 2,017.0	$ 657.8	$ (27.3)	$ 1,386.5

Operations and Significant Accounting Policies

6 Months Ended

Jun. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Operations and Significant Accounting Policies [Text Block]

OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Inventories – Net. Inventories are stated at the lower of cost or net realizable value. 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 segment and Corporate and Other operations are carried at an average cost, first-in, first-out or specific identification basis.



Inventories – Net	June 30, 2017			December 31, 2016
Millions
Fuel (a)		$45.0			$43.9
Materials and Supplies	48.0			48.7
Raw Materials	2.8			2.9
Work in Progress	0.3			1.0
Finished Goods	8.3			8.6
Reserve for Obsolescence	(1.0		)	(0.9		)
Total Inventories – Net		$103.4			$104.2


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



Prepayments and Other Current Assets	June 30, 2017		December 31, 2016
Millions
Deferred Fuel Adjustment Clause		$16.7		$18.6
Restricted Cash	3.7		2.2
Other	18.4		19.5
Total Prepayments and Other Current Assets		$38.8		$40.3



Other Non-Current Assets	June 30, 2017		December 31, 2016
Millions
Contract Payment		$28.4		$29.6
Finance Receivable	11.5		11.5
Restricted Cash	8.6		8.6
Other	56.3		56.8
Total Other Non-Current Assets		$104.8		$106.5

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)



Other Current Liabilities	June 30, 2017		December 31, 2016
Millions
PSAs		$24.7		$24.6
Other	45.4		49.1
Total Other Current Liabilities		$70.1		$73.7



Other Non-Current Liabilities	June 30, 2017		December 31, 2016
Millions
Asset Retirement Obligation		$158.2		$136.6
PSAs	101.5		113.8
Contingent Consideration (a)	5.5		25.0
Other	43.9		47.3
Total Other Non-Current Liabilities		$309.1		$322.7


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

Supplemental Statement of Cash Flows Information.



Six Months Ended June 30,	2017		2016
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$32.5		$32.9
Cash Paid During the Period for Income Taxes		$0.3		$0.4
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(0.4)		$(24.4)
Capitalized Asset Retirement Costs		$19.7		$2.3
AFUDC–Equity		$0.4		$1.2
ALLETE Common Stock Contributed to the Pension Plans		$13.5	—

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

New Accounting Pronouncements.

Recently Adopted Pronouncements

Simplifying the Measurement of Inventory. In 2015, the FASB issued an accounting standards update which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance was adopted in the first quarter of 2017 and did not have a material impact on our Consolidated Financial Statements.

Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued guidance to simplify the accounting for share-based payment transactions by requiring all excess tax benefits and deficiencies to be recognized in income tax expense or benefit in earnings, thus eliminating the requirement to classify the excess tax benefit and deficiencies as additional paid-in capital. Under the new guidance, an entity makes an accounting policy election to either estimate the expected forfeiture awards or account for forfeitures as they occur. This accounting guidance was adopted in the first quarter of 2017. The adoption of this guidance is expected to result in a less than $1 million impact to income tax expense (benefit) annually.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Clarifying the Definition of a Business. In January 2017, the FASB issued clarifying guidance on the definition of a business and provided additional guidance to assist with evaluating whether transactions are to be accounted for as an acquisition or disposal of a group of assets or a business. The clarifying guidance will also impact other areas including the accounting for goodwill and consolidation. This accounting guidance was adopted in the first quarter of 2017 and did not have an impact on our Consolidated Financial Statements.

Stock Compensation: Scope of Modification Accounting. In May 2017, the FASB issued additional clarifying guidance regarding circumstances where changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting under ASC 718. The guidance provides specific situations that would be excluded from effects of a modification including if the fair value, vesting conditions, and classification are the same before and after modification. The amendments in this update will be applied prospectively to awards modified on or after adoption. This accounting guidance was adopted by the Company in the second quarter of 2017 and did not have an impact on our Consolidated Financial Statements.

Recently Issued Pronouncements

Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued updated guidance which simplifies the measurement of goodwill impairment by removing step two of the goodwill impairment test that requires the determination of the fair value of individual assets and liabilities of a reporting unit. The updated guidance requires goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued guidance to improve the presentation of net periodic pension and postretirement benefit costs. Under the revised guidance of ASC 715, an entity shall present the service cost component of the net periodic benefit cost in the same income statement line as other employee compensation costs arising from services rendered during the period. The guidance also allows only the service cost component of the periodic cost to be eligible for capitalization. The standard will be applied retrospectively for income statement presentation, and prospectively for capitalization of service cost components. Although the non-service components of pension and other postretirement benefit costs are excluded from capitalization, they are considered allowable costs for ratemaking and will be recorded as regulatory assets or liabilities for the regulated portion of the Company. We do not expect there to be a material impact on the Consolidated Financial Statements with the adoption of the updated guidance which is effective for the Company beginning in the first quarter of 2018.

Revenue from Contracts with Customers. In 2014, the FASB issued amended revenue recognition guidance that clarifies the principles for recognizing revenue from contracts with customers by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The guidance requires an entity to recognize revenue in a manner that depicts 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. As of June 30, 2017, the Company has reviewed nearly all of its revenue streams and contracts for its regulated businesses, completing the preliminary evaluations of the impact of this guidance. Additional review and analysis is being performed on the Company’s energy infrastructure and related services businesses. The Company does not expect the update to significantly affect results of its regulated operations, which represent the majority of revenue, or the remaining revenue from its energy infrastructure and related services businesses. Management continues to monitor and evaluate the unresolved industry related issues, primarily around step versus strip pricing, long-term contract minimums and principal versus agent considerations. The Company currently expects to implement the new standard on a modified retrospective basis which requires application of standards to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017, recognized as an adjustment to retained earnings on the Consolidated Balance Sheet. The Company will adopt this guidance for our fiscal year beginning January 1, 2018.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (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. We are currently evaluating the impact of the revised lease guidance on our Consolidated Financial Statements.

Financial Instruments. In January 2016, the FASB issued an accounting standard update which requires entities to measure their investments at fair value and recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The updated guidance is effective for the Company beginning in the first quarter of 2018 and will result in a cumulative‑effect adjustment to retained earnings on the Consolidated Balance Sheet in the fiscal year of adoption. We have performed a preliminary evaluation of the impact of this update, and based on that evaluation, we do not expect the adoption of the update to have a material impact on our Consolidated Financial Statements.

Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standard update which addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero‑coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. This accounting guidance is effective for the Company beginning in the first quarter of 2018. We do not expect the update to have a material impact on our Consolidated Statement of Cash Flows.

Statement of Cash Flows: Restricted Cash. In November 2016, the FASB issued an accounting standard update related to the presentation of restricted cash in the Company’s Consolidated Statement of Cash Flows. The update requires that the Consolidated Statement of Cash Flows explain the change during the period in cash, cash equivalents and restricted cash. Restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. This accounting guidance is effective for the Company beginning in the first quarter of 2018 and will be applied retrospectively to all periods presented. The guidance will result in changes to the Company’s Consolidated Statement of Cash Flows such that restricted cash amounts will be included in the beginning-of-period and end-of-period cash and cash equivalents totals when adopted for our fiscal year beginning January 1, 2018.

Revision of Prior Balance Sheet. During the first quarter of 2017, the Company identified an error related to the deferred income tax treatment associated with its Wholesale and Retail Contra AFUDC Regulatory Liability. The Company evaluated the materiality of the error and concluded that it was not material to any previously issued historical financial statements. The Company has revised its Consolidated Balance Sheet as of December 31, 2016, by decreasing Regulatory Assets and Deferred Income Taxes by $29.5 million. The correction had no impact on our Consolidated Statement of Income.

Reclassification of Prior Income Statement. Beginning with the second quarter of 2017, the Company enhanced its presentation of Operating Revenue and certain Operating Expenses on the Consolidated Statement of Income by presenting the caption Operating Revenue separately as Operating Revenue – Utility and Operating Revenue – Non-utility. In conformity with the current presentation, we now present $234.9 million and $487.2 million of Operating Revenue as Operating Revenue – Utility for the quarter and six months ended June 30, 2016, respectively, as it is generated from our regulated utility operations. Non-utility revenue of $79.9 million and $161.4 million for the quarter and six months ended June 30, 2016, respectively, is now presented as Operating Revenue – Non-utility. In addition, the captions Fuel and Purchased Power and Cost of Sales have been updated to Fuel, Purchased Power and Gas – Utility and Cost of Sales – Non-utility. As a result, we have reclassified $0.9 million relating to the cost of gas sales at SWL&P from Cost of Sales – Non-utility to Fuel, Purchased Power and Gas – Utility for the quarter ended June 30, 2016, and $3.9 million for the six months ended June 30, 2016.

Investments

6 Months Ended

Jun. 30, 2017

Investments [Abstract]

Investments [Text Block]

INVESTMENTS

Investments. As of June 30, 2017, 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, 2017		December 31, 2016
Millions
ALLETE Properties		$29.5		$31.7
Available-for-sale Securities (a)	20.6		18.8
Cash Equivalents	2.4		1.3
Other	3.7		3.8
Total Other Investments		$56.2		$55.6


(a)	As of June 30, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.6 million, in one year to less than three years was $2.7 million, in three years to less than five years was $6.8 million and in five or more years was $2.9 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 impairment was recorded for the quarter and six months ended June 30, 2017, and 2016.

Available-for-Sale Investments. We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.

Gross realized and unrealized gains and losses on our available-for-sale investments were immaterial for the quarter and six months ended June 30, 2017, and 2016.

Acquisitions

6 Months Ended

Jun. 30, 2017

Business Combinations [Abstract]

Acquisitions [Text Block]

ACQUISITIONS

The following acquisitions are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, 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.

2016 Activity.

Acquisition of Non-Controlling Interest. In April 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns the 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 became a wholly-owned subsidiary of ALLETE Clean Energy.

WEST. In October 2016, U.S. Water Services acquired 100 percent of Water & Energy Systems Technology of Nevada, Inc. (WEST). Total consideration for the transaction was $6.7 million. Consideration of $5.9 million was paid in cash on the acquisition date, working capital adjustments of $0.2 million were paid in the first six months of 2017 and a $0.6 million payment is due in April 2018. WEST is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southwestern United States.

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 the second quarter of 2017, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.

NOTE 3. ACQUISITIONS (Continued)

2016 Activity (Continued)



Millions
Assets Acquired
Cash and Cash Equivalents		$0.1
Other Current Assets	1.0
Customer Relationships (a)	2.8
Goodwill (a)(b)	4.2
Other Non-Current Assets	0.1
Total Assets Acquired		$8.2
Liabilities Assumed
Current Liabilities		$0.3
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.5
Net Identifiable Assets Acquired		$6.7


(a)	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 4. Goodwill and Intangible Assets.)


(b)	For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisition-related costs were immaterial, expensed as incurred during 2016 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

- Definition

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

+ 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=65885119&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=65885119&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=65885119&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
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+ Details

Goodwill and Intangible Assets

6 Months Ended

Jun. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The aggregate carrying amount of goodwill was $131.4 million as of June 30, 2017, and $131.2 million as of December 31, 2016. Changes to goodwill for the six months ended June 30, 2017, relate to the finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST.

Balances of intangible assets, net, excluding goodwill as of June 30, 2017, are as follows:



	December 31, 2016		Amortization	June 30, 2017
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	$59.3		$(2.3)		$57.0
Developed Technology and Other (a)	6.3		(0.5)	5.8
Total Definite-Lived Intangible Assets	65.6		(2.8)	62.8
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		n/a	16.6
Total Intangible Assets		$82.2	$(2.8)		$79.4


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

Customer relationships have a remaining useful life of approximately 21 years, and developed technology and other have remaining useful lives ranging from approximately 2 years to approximately 12 years (weighted average of approximately 8 years). The weighted average remaining useful life of all definite-lived intangible assets as of June 30, 2017, is approximately 19 years.

NOTE 4. GOODWILL AND INTANGIBLE ASSETS (Continued)

Amortization expense of intangible assets was $1.4 million and $2.8 million for the quarter and six months ended June 30, 2017, respectively ($1.2 million and $2.5 million for the quarter and six months ended June 30, 2016, respectively). Accumulated amortization was $12.1 million as of June 30, 2017 ($9.3 million as of December 31, 2016). The estimated amortization expense for definite-lived intangible assets for the remainder of 2017 is $2.7 million. Estimated annual amortization expense for definite-lived intangible assets is $5.1 million in 2018, $4.8 million in 2019, $4.5 million in 2020, $4.4 million in 2021 and $41.3 million thereafter.

- Definition

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

+ References + Details

Fair Value

6 Months Ended

Jun. 30, 2017

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 9. Fair Value to the Consolidated Financial Statements in our 2016 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, 2017, and December 31, 2016. 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.



	Fair Value as of June 30, 2017
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 and Governmental Debt Securities	—			$13.0	—		13.0
Cash Equivalents	2.4		—		—		2.4
Total Fair Value of Assets		$10.0		$13.0	—			$23.0

Liabilities (b)
Deferred Compensation	—			$17.6	—			$17.6
U.S. Water Services Contingent Consideration	—		—			$5.5	5.5
Total Fair Value of Liabilities	—			$17.6		$5.5		$23.1
Total Net Fair Value of Assets (Liabilities)		$10.0	$(4.6)		$(5.5)		$(0.1)


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


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

NOTE 5. FAIR VALUE (Continued)



	Fair Value as of December 31, 2016
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.1	—		—			$7.1
Available-for-sale – Corporate and Governmental Debt Securities	—			$11.7	—		11.7
Cash Equivalents	1.3		—		—		1.3
Total Fair Value of Assets		$8.4		$11.7	—			$20.1

Liabilities (b)
Deferred Compensation	—			$16.0	—			$16.0
U.S. Water Services Contingent Consideration	—		—			$25.0	25.0
Total Fair Value of Liabilities	—			$16.0		$25.0		$41.0
Total Net Fair Value of Assets (Liabilities)		$8.4	$(4.3)		$(25.0)		$(20.9)


(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 liability in the preceding tables is the result of the 2015 acquisition of U.S. Water Services. Changes in the U.S. Water Services Contingent Consideration can result from modifications to the shareholder agreement, changes in discount rates, timing of milestones that trigger payment, or the timing and amount of earnings estimates. The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of June 30, 2017. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2016		$25.0
Accretion	0.6
Payments (a)	(19.7		)
Changes in Cash Flow Projections (a)	(0.4		)
Balance as of June 30, 2017		$5.5


(a)	Payments and changes in cash flow projections reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, which were paid in the first six months of 2017.

For the six months ended June 30, 2017, and the year ended December 31, 2016, 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 following table, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed in the following table 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, 2017	$1,529.6	$1,634.6
December 31, 2016	$1,569.1	$1,653.8

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 quarter and six months ended June 30, 2017, and the year ended December 31, 2016, there were no triggering events or indicators of impairment for these non-financial assets.

- Definition

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

+ References + Details

Regulatory Matters

6 Months Ended

Jun. 30, 2017

Regulated Operations [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

Regulatory matters are summarized in Note 4. Regulatory Matters to our Consolidated Financial Statements in our 2016 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, FERC or PSCW.

2010 Minnesota General Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable, and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $24.4 million and $48.6 million for the quarter and six months ended June 30, 2017, respectively ($23.5 million and $48.9 million for the quarter and six months ended June 30, 2016, respectively).

2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 9 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $55 million in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017.

On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review has progressed, Minnesota Power now expects its final rate request to be approximately $49 million on an annualized basis. Management has evaluated the need for a reserve for interim rate refunds and concluded that a reserve is not necessary as of June 30, 2017. Management evaluates the need for reserves for interim rates each reporting period.

As part of its 2016 general rate case and through its 2017 remaining life depreciation petition filed on February 1, 2017, Minnesota Power is seeking an extension of the recovery period for Boswell to better reflect recent environmental investments at the facility and mitigate rate increases for our customers. If approved, annual depreciation expense will be reduced by approximately $25 million. If the requested recovery period extension is not approved, we would expect final rates to be increased by a similar amount, subject to regulatory approval. We cannot predict the level of final rates that may be authorized by the MPUC.

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking law in 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 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice, providing Minnesota Power the option to refile the petition with additional information or file a new petition. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017. The rate adjustments are intended to be revenue and cash flow neutral to Minnesota Power.

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 wholesale contracts include a termination clause requiring a three-year notice to terminate.

In 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. No termination notice may be given for this contract prior to June 30, 2025. The electric service agreements with SWL&P and another municipal customer are effective through July 31, 2020, and June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to July 31, 2017. The other municipal customer provided termination notice for its contract in June 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. 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.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Also in 2015, Minnesota Power amended its wholesale electric contracts with 14 municipal customers, extending the contract terms through December 31, 2024. No termination notices may be given prior to December 31, 2021. 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.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In a February 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates 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 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see Great Northern Transmission Line.), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission cost recovery filings.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to Bison and the restoration and repair of Thomson. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in a December 2016 order, which allows 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. The approval is on a provisional basis pending the outcome of Minnesota Power’s 2016 general rate case. (See 2016 Minnesota General Rate Case.)

In a November 2016 order, the MPUC directed Minnesota Power to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in operating revenue of $15.0 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income for the year ended December 31, 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order and provided for a comment period which expired on June 30, 2017.

Prior to the November 2016 MPUC order, Minnesota Power accounted for North Dakota investment tax credits based on the 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 had 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 were included in the ALLETE consolidated group.

Minnesota Power also has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See Minnesota Solar Energy Standard.) Currently, there is no approved customer billing rate for solar costs.

Environmental Improvement Rider. 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. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a December 2016 order; however, in an order dated March 22, 2017, the MPUC approved a request by Minnesota Power to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.)

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order that allows for a 10.9 percent return on common equity. In June 2016, SWL&P filed a rate increase request with the PSCW requesting an average increase of 3.1 percent for retail customers (3.5 percent increase in electric rates; 1.3 percent decrease in natural gas rates; and 7.8 percent increase in water rates). The filing seeks an overall return on equity of 10.9 percent and a 55 percent equity ratio. At a hearing on July 13, 2017, the PSCW approved a return on common equity of 10.5 percent and a 55 percent equity ratio. On an annualized basis, we expect additional revenue of approximately $2.5 million. An order from the PSCW detailing the effective date of final rates is expected in the third quarter of 2017.

NOTE 6. REGULATORY MATTERS (Continued)

Integrated Resource Plan. In 2015, Minnesota Power filed its 2015 IRP with the MPUC which included 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 contained steps in Minnesota Power’s EnergyForward strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in September 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 a July 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for Taconite Harbor, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. In October 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018. On July 28, 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas energy PPA. These agreements will be subject to MPUC approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. This resource package is the next step in Minnesota Power’s EnergyForward strategic plan. Minnesota Power’s next IRP is required to be filed by February 1, 2018; however, Minnesota Power filed a request with the MPUC on June 8, 2017, to delay the filing deadline until at least February 1, 2019.

Great Northern Transmission Line. 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. In 2015, a certificate of need was approved by the MPUC. Based on this approval, 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 cost recovery filings. (See Transmission Cost Recovery Rider.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected 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, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as contributions in aid of construction. Total project costs of $61.1 million have been incurred through June 30, 2017, of which $31.6 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 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.

Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year. On April 3, 2017, Minnesota Power submitted its 2016 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $5.5 million based upon MPUC procedures. In an order dated June 22, 2017, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive which was recorded as revenue and as a regulatory asset in the second quarter of 2017. The approved financial incentive will be recovered through customer billing rates in 2017 and 2018. In 2016, the CIP financial incentive of $7.5 million was recognized in the third quarter. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

MISO Return on Equity Complaints. In 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 2015, a federal administrative law judge ruled on the complaint proposing a reduction in the base return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In September 2016, the FERC issued an order affirming the administrative law judge’s recommendation.

NOTE 6. REGULATORY MATTERS (Continued)

MISO Return on Equity Complaints (Continued)

In 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. In June 2016, a federal administrative law judge ruled on the additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending. The final decision from the FERC is not expected to have a material impact on our Consolidated Financial Statements.

Minnesota Solar Energy Standard. In 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 40 kW or less. In a February 2016 order finalized in December 2016, the MPUC approved Camp Ripley, a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern 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 is owned and operated by Minnesota Power. Minnesota Power believes Camp Ripley and the community solar garden project will meet approximately one-third of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal 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. This proposal to incentivize customer-sited solar installations is expected to meet a portion of the required mandate related to solar photovoltaic devices with a nameplate capacity of 40 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 for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.



Regulatory Assets and Liabilities	June 30, 2017		December 31, 2016
Millions
Current Regulatory Assets
Deferred Fuel Adjustment Clause		$16.7		$18.6
Total Current Regulatory Assets	16.7		18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans	223.4		226.1
Income Taxes (a)	35.0		33.8
Asset Retirement Obligations	28.4		26.0
Cost Recovery Riders	13.8		30.5
Conservation Improvement Program	7.1		4.0
PPACA Income Tax Deferral	5.0		5.0
Other	11.8		4.7
Total Non-Current Regulatory Assets	324.5		330.1
Total Regulatory Assets		$341.2		$348.7

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$56.9		$56.8
North Dakota Investment Tax Credits	27.7		28.2
Plant Removal Obligations	19.0		19.1
Income Taxes	18.8		19.1
Other	3.4		2.6
Total Non-Current Regulatory Liabilities		$125.8		$125.8


(a)	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

Investment in ATC

6 Months Ended

Jun. 30, 2017

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, 2017, our equity investment in ATC was $143.1 million ($135.6 million at December 31, 2016). In the first six months of 2017, we invested $5.0 million in ATC, and on July 31, 2017, we invested an additional $1.6 million. We expect to make additional investments of approximately $4.3 million in 2017.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2016		$135.6
Cash Investments	5.0
Equity in ATC Earnings	11.4
Distributed ATC Earnings	(8.9		)
Equity Investment Balance as of June 30, 2017		$143.1

In September 2016, the FERC issued an order reducing ATC’s authorized return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. Prior to this order, ATC had been allowed a return on equity of 12.2 percent which had been impacted by reductions for estimated refunds related to complaints filed with the FERC by several customers located within the MISO service area.

In June 2016, a federal administrative law judge ruled on an additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending. (See Note 6. Regulatory Matters.) 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.

Short-Term and Long-Term Debt

6 Months Ended

Jun. 30, 2017

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, 2017, and December 31, 2016:



June 30, 2017	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$118.2	$(0.5)		$117.7
Long-Term Debt	1,411.4		(10.0)	1,401.4
Total Debt		$1,529.6	$(10.5)		$1,519.1



December 31, 2016	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$188.3	$(0.6)		$187.7
Long-Term Debt	1,380.8		(10.4)	1,370.4
Total Debt		$1,569.1	$(11.0)		$1,558.1

On June 1, 2017, ALLETE issued $80.0 million of its senior unsecured notes (the Notes) to certain institutional buyers in the private placement market. The Notes were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes bear interest at 3.11 percent and mature on June 1, 2027. Interest on the Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2017. ALLETE has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes may be used to redeem debt, fund corporate growth opportunities and for general corporate purposes.

NOTE 8. SHORT-TERM AND LONG-TERM DEBT (Continued)

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, 2017, our ratio was approximately 0.43 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of June 30, 2017, ALLETE was in compliance with its financial covenants.

Income Tax Expense

6 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017			2016
Millions
Current Tax Expense (a)
Federal	—		—			—			—
State	$0.1		$0.1				$0.2		$0.2
Total Current Tax Expense	$0.1		$0.1				$0.2		$0.2
Deferred Tax Expense
Federal	$3.8			$2.1		$11.1				$6.7
State	3.6		2.7			9.5			7.5
Investment Tax Credit Amortization	(0.2	)	(0.2		)	(0.4		)	(0.4		)
Total Deferred Tax Expense	$7.2			$4.6		$20.2				$13.8
Total Income Tax Expense	$7.3			$4.7		$20.4				$14.0


(a)	For the quarter and six months ended June 30, 2017, and 2016, 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.



	Quarter Ended						Six Months Ended
Reconciliation of Taxes from Federal Statutory	June 30,						June 30,
Rate to Total Income Tax Expense	2017			2016			2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$44.2			$29.5			$106.3			$85.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$15.5			$10.3			$37.2			$29.8
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	2.4			1.8			6.3			5.0
Production Tax Credits	(10.0		)	(6.6		)	(23.0		)	(20.5		)
Other	(0.6		)	(0.8		)	(0.1		)	(0.3		)
Total Income Tax Expense		$7.3			$4.7			$20.4			$14.0

For the six months ended June 30, 2017, the effective tax rate was 19.2 percent (16.4 percent for the six months ended June 30, 2016).

NOTE 9. INCOME TAX EXPENSE (Continued)

Uncertain Tax Positions. As of June 30, 2017, we had gross unrecognized tax benefits of $1.9 million ($2.0 million as of December 31, 2016). Of the total gross unrecognized tax benefits, $0.7 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 has no open federal or state audits, and is no longer subject to federal examination for years before 2013, or state examination for years before 2012.

Reclassifications Out of Accumulated Other Comprehensive Loss	6 Months Ended
	Jun. 30, 2017
Equity [Abstract]
Reclassifications Out of Accumulated Other Comprehensive Income (Loss) [Text Block]	RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE 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 currency translation adjustments, unrealized gains and losses on available-for-sale securities and defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits. For the quarter and six months ended June 30, 2017, and 2016, reclassifications out of accumulated other comprehensive loss for the Company were not material. Changes in accumulated other comprehensive loss for the six months ended June 30, 2017, are presented on the Consolidated Statement of Shareholders’ Equity.

- Definition

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

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