Acquisitions [Text Block]

Investments [Text Block]

INVESTMENTS

Investments. As of September 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	September 30, 2017		December 31, 2016
Millions
ALLETE Properties		$28.8		$31.7
Available-for-sale Securities (a)	21.0		18.8
Cash Equivalents	2.2		1.3
Other	3.8		3.8
Total Other Investments		$55.8		$55.6


(a)	As of September 30, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.1 million, in one year to less than three years was $3.2 million, in three years to less than five years was $4.2 million and in five or more years was $1.6 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 nine months ended September 30, 2017, and 2016.

Available-for-Sale Securities. We account for our available-for-sale securities 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 securities were immaterial for the quarter and nine months ended September 30, 2017, and 2016.

Acquisitions

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

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 nine months ended September 30, 2017, and 2016.

2017 Activity.

Tonka Water. On September 1, 2017, U.S. Water Services acquired 100 percent of Tonka Water. Total consideration for the transaction was $19.4 million, including a preliminary working capital adjustment. Consideration of $19.0 million was paid in cash on the acquisition date with an estimated payment of $0.4 million to be made in the fourth quarter of 2017 with the finalization of the working capital adjustment. Tonka Water is a supplier of municipal and industrial water treatment systems and will expand U.S. Water Services’ geographic and customer markets.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as shown in the following table. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to working capital; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.

NOTE 3. ACQUISITIONS (Continued)

2017 Activity (Continued)



Millions
Assets Acquired
Cash and Cash Equivalents		$1.6
Accounts Receivable	5.1
Other Current Assets	4.4
Trade Names (a)	0.9
Goodwill (a)(b)	18.5
Other Non-Current Assets	0.2
Total Assets Acquired		$30.7
Liabilities Assumed
Current Liabilities		$10.6
Non-Current Liabilities	0.7
Total Liabilities Assumed		$11.3
Net Identifiable Assets Acquired		$19.4

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


(b)	Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill.

Acquisition-related costs were immaterial, expensed as incurred during 2017 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

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.

Goodwill and Intangible Assets

9 Months Ended

Sep. 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 $149.9 million as of September 30, 2017 ($131.2 million as of December 31, 2016). Changes to goodwill for the nine months ended September 30, 2017, relate to U.S. Water Services’ acquisition of Tonka Water and the finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST.

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



	December 31, 2016		Additions (a)		Amortization	September 30, 2017
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	$59.3		—		$(3.4)		$55.9
Developed Technology and Other (b)	6.3			$0.9	(0.7)	6.5
Total Definite-Lived Intangible Assets	65.6		0.9		(4.1)	62.4
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$82.2		$0.9	$(4.1)		$79.0


(a)	Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 3. Acquisitions.)


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

Customer relationships have a remaining useful life of approximately 20 years, and developed technology and other have remaining useful lives ranging from approximately 1 year to approximately 11 years (weighted average of approximately 7 years). The weighted average remaining useful life of all definite-lived intangible assets as of September 30, 2017, is approximately 19 years.

NOTE 4. GOODWILL AND INTANGIBLE ASSETS (Continued)

Amortization expense for intangible assets was $1.3 million and $4.1 million for the quarter and nine months ended September 30, 2017, respectively ($1.3 million and $3.8 million for the quarter and nine months ended September 30, 2016, respectively). Accumulated amortization was $13.4 million as of September 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 $1.5 million. Estimated annual amortization expense for definite-lived intangible assets is $5.3 million in 2018, $4.9 million in 2019, $4.7 million in 2020, $4.6 million in 2021 and $41.4 million thereafter.

- Definition

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

+ References + Details

Fair Value

9 Months Ended

Sep. 30, 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 September 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 September 30, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$10.9	—		—			$10.9
Available-for-sale – Corporate and Governmental Debt Securities	—			$10.1	—		10.1
Cash Equivalents	2.2		—		—		2.2
Total Fair Value of Assets		$13.1		$10.1	—			$23.2

Liabilities (b)
Deferred Compensation	—			$18.7	—			$18.7
U.S. Water Services Contingent Consideration	—		—			$5.6	5.6
Total Fair Value of Liabilities	—			$18.7		$5.6		$24.3
Total Net Fair Value of Assets (Liabilities)		$13.1	$(8.6)		$(5.6)		$(1.1)


(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 September 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	0.7
Payments (a)	(19.7		)
Changes in Cash Flow Projections (a)	(0.4		)
Balance as of September 30, 2017		$5.6


(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, and were paid in the first half of 2017.

For the nine months ended September 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
September 30, 2017	$1,519.0	$1,627.9
December 31, 2016	$1,569.1	$1,653.8

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 quarter and nine months ended September 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

9 Months Ended

Sep. 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 $23.1 million and $71.7 million for the quarter and nine months ended September 30, 2017, respectively ($25.1 million and $73.9 million for the quarter and nine months ended September 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’s final rate request is approximately $49 million on an annualized basis. A report and recommendation from the administrative law judge is scheduled to be issued in November 2017, with a final decision from the MPUC expected in January 2018. Management has evaluated the need for a reserve for interim rate refunds and concluded that a reserve is not necessary as of September 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 the requested recovery period extension is approved, annual depreciation expense will be reduced by approximately $25 million. If 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 rate adjustments are intended to be revenue and cash flow neutral to Minnesota Power. 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; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism. On September 29, 2017, Minnesota Power informed its EITE customers that it has suspended the EITE discount due to a concern it is not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and upcoming decisions in its 2016 general rate case.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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

Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through December 31, 2032, subject to bankruptcy court approval. No termination notice may be given for this contract prior to June 30, 2025. The wholesale electric service contracts with SWL&P and another municipal customer are effective through October 31, 2020, and June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to October 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.

Minnesota Power’s wholesale electric contracts with 14 municipal customers are effective 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. The cost recovery rider 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. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC at a hearing on September 28, 2017.

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 approximately $15 million in the third quarter of 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an approximately $9 million charge to net income in the third quarter of 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.

At a hearing on September 28, 2017, the MPUC modified its November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long‑standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in operating revenue of approximately $14 million in the third quarter of 2017. The North Dakota investment tax credits were reestablished as income tax credits in Corporate and Other, resulting in an approximately $8 million increase to net income in the third quarter of 2017.

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 Corporate and Other operations.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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.)

Fuel Adjustment Clause Reform Pilot. At a hearing on October 19, 2017, the MPUC adopted a three-year pilot program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The decision, subject to an MPUC order, would change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forwarded‑looking FAC with a subsequent prudence review and true-up to actual allowed costs on an annual basis. The annual budget projection filing would also include an adjustment to the base cost of fuel. The MPUC will seek input from the utilities and other stakeholders on the detailed implementation steps and transition accounting needed to adopt the change in regulatory accounting method from the current FAC. Transition considerations would need to include the recovery of the current regulatory asset for deferred fuel costs consistent with other regulatory accounting transition precedents for similar matters. Other details of the transition including budgeting methodology and approval, tracker accounting for the differences between actual costs and the budgeted amounts, and the annual true-up and collection or refund process to customers will be determined by the MPUC upon consideration of each utility’s compliance filings. Based on the discussion at the October 19, 2017 hearing, this pilot is not expected to start until mid-2019.

2016 Wisconsin General Rate Case. In June 2016, SWL&P filed a rate increase request with the PSCW requesting an average increase of 3.1 percent for retail customers. The filing sought an overall return on equity of 10.9 percent and a 55 percent equity ratio. In an order dated August 9, 2017, the PSCW approved SWL&P’s rate increase request allowing for a 10.5 percent return on common equity and a 55 percent equity ratio. The order authorizes SWL&P to collect on average a 2.9 percent increase in rates for retail customers (3.8 percent increase in electric rates; 4.8 percent decrease in natural gas rates; and 9.8 percent increase in water rates). Final rates became effective on August 14, 2017. On an annualized basis, SWL&P will collect additional revenue of approximately $2.5 million.

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. In an order dated September 19, 2017, the MPUC approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2019, and Minnesota Power’s request that approval for the natural gas energy PPA be decided through an administrative law judge process. The administrative law judge is expected to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second half of 2018. The MPUC did not take any action regarding the wind and solar energy PPAs which will be refiled separately from the natural gas energy PPA.

NOTE 6. REGULATORY MATTERS (Continued)

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 $66.9 million have been incurred through September 30, 2017, of which $36.8 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.

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, which 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.

NOTE 6. REGULATORY MATTERS (Continued)

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	September 30, 2017		December 31, 2016
Millions
Current Regulatory Assets
Deferred Fuel Adjustment Clause		$20.2		$18.6
Total Current Regulatory Assets	20.2		18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans	221.4		226.1
Income Taxes (a)	35.7		33.8
Asset Retirement Obligations	29.8		26.0
Cost Recovery Riders	5.2		30.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	4.9		4.0
Other	8.6		4.7
Total Non-Current Regulatory Assets	310.6		330.1
Total Regulatory Assets		$330.8		$348.7

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$57.0		$56.8
Plant Removal Obligations	19.2		19.1
Income Taxes	18.6		19.1
North Dakota Investment Tax Credits	13.9		28.2
Other	2.8		2.6
Total Non-Current Regulatory Liabilities		$111.5		$125.8


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

Investment in ATC

9 Months Ended

Sep. 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 September 30, 2017, our equity investment in ATC was $146.0 million ($135.6 million at December 31, 2016). In the first nine months of 2017, we invested $6.6 million in ATC, and on October 31, 2017, we invested an additional $1.2 million. We do not expect to make any additional investments in 2017.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2016		$135.6
Cash Investments	6.6
Equity in ATC Earnings	17.3
Distributed ATC Earnings	(13.5		)
Equity Investment Balance as of September 30, 2017		$146.0

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.

NOTE 7. INVESTMENT IN ATC (Continued)

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

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

The following tables present the Company’s short-term and long-term debt as of September 30, 2017, and December 31, 2016:



September 30, 2017	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$64.6	$(0.5)		$64.1
Long-Term Debt	1,454.4		(9.8)	1,444.6
Total Debt		$1,519.0	$(10.3)		$1,508.7



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.

On August 25, 2017, ALLETE entered into a $40.0 million term loan agreement (Term Loan). The Term Loan is an unsecured, single draw loan that is due on August 25, 2020, and may be prepaid at any time subject to a make-whole provision. The interest rate on the Term Loan is equal to LIBOR plus 1.025 percent. Proceeds from the Term Loan will be used for general corporate purposes.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of September 30, 2017, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of September 30, 2017, ALLETE was in compliance with its financial covenants.

Income Tax Expense

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Millions
Current Income Tax Expense (a)
Federal	—			—			—			—
State		$0.1		—				$0.3		$0.2
Total Current Income Tax Expense		$0.1		—				$0.3		$0.2
Deferred Income Tax Expense
Federal	$9.2				$0.4		$20.3				$7.1
State	5.0			1.4			14.5			8.9
Investment Tax Credit Amortization	(0.1		)	(0.1		)	(0.5		)	(0.5		)
Total Deferred Income Tax Expense	$14.1				$1.7		$34.3				$15.5
Total Income Tax Expense	$14.2				$1.7		$34.6				$15.7


(a)	For the quarter and nine months ended September 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						Nine Months Ended
Reconciliation of Taxes from Federal Statutory	September 30,						September 30,
Rate to Total Income Tax Expense	2017			2016			2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$59.1			$42.0			$165.4			$127.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$20.7			$14.7			$57.9			$44.5
Increase (Decrease) in Income Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	3.3			0.9			9.6			5.9
Production Tax Credits	(10.4		)	(14.0		)	(33.4		)	(34.5		)
Other	0.6			0.1			0.5			(0.2		)
Total Income Tax Expense		$14.2			$1.7			$34.6			$15.7

For the nine months ended September 30, 2017, the effective tax rate was 20.9 percent (12.3 percent for the nine months ended September 30, 2016).

Uncertain Tax Positions. As of September 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	9 Months Ended
	Sep. 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 nine months ended September 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 nine months ended September 30, 2017, are presented on the Consolidated Statement of Shareholders’ Equity.

Earnings Per Share and Common Stock

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Earnings Per Share and Common Stock [Text Block]

EARNINGS PER SHARE AND COMMON STOCK

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the nine months ended September 30, 2017, and 2016, no options to purchase shares of ALLETE common stock were excluded from the computation of diluted earnings per share.



			2017					2016
Reconciliation of Basic and Diluted			Dilutive					Dilutive
Earnings Per Share	Basic		Securities	Diluted		Basic		Securities	Diluted
Millions Except Per Share Amounts
Quarter ended September 30,
Net Income Attributable to ALLETE		$44.9			$44.9		$40.3			$40.3
Average Common Shares	51.0		0.2	51.2		49.4		0.1	49.5
Earnings Per Share		$0.88			$0.88		$0.82			$0.81
Nine Months Ended September 30,
Net Income Attributable to ALLETE		$130.8			$130.8		$111.0			$111.0
Average Common Shares	50.7		0.2	50.9		49.3		0.1	49.4
Earnings Per Share		$2.58			$2.57		$2.25			$2.25

Contributions to Pension. For the nine months ended September 30, 2017, we contributed 0.2 million shares of ALLETE common stock to our defined benefit pension plans, which had an aggregate value of $13.5 million when contributed (no shares were contributed to the defined benefit pension plans for the nine months ended September 30, 2016). These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.

Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS



	Pension						Other Postretirement
Components of Net Periodic Benefit Cost (Income)	2017			2016			2017			2016
Millions
Quarter Ended September 30,
Service Cost		$2.6			$2.0			$1.1			$1.0
Interest Cost	8.1			8.2			2.0			1.9
Expected Return on Plan Assets	(10.6		)	(10.7		)	(2.6		)	(2.8		)
Amortization of Prior Service Credits	—			—			(0.5		)	(0.7		)
Amortization of Net Loss	2.5			2.4			—			—
Net Periodic Benefit Cost (Income)		$2.6			$1.9		—			$(0.6)

Nine Months Ended September 30,
Service Cost		$7.7			$6.1			$3.3			$3.0
Interest Cost	24.4			24.4			5.8			5.6
Expected Return on Plan Assets	(31.8		)	(32.0		)	(7.9		)	(8.4		)
Amortization of Prior Service Credits	—			—			(1.5		)	(2.2		)
Amortization of Net Loss	7.4			7.3			0.2			0.1
Net Periodic Benefit Cost (Income)		$7.7			$5.8		$(0.1)			$(1.9)

Employer Contributions. For the nine months ended September 30, 2017, we contributed $1.7 million in cash and $13.5 million in ALLETE common stock to the defined benefit pension plans ($6.3 million in cash for the nine months ended September 30, 2016); we do not expect to make additional contributions to our defined benefit pension plans in 2017. For the nine months ended September 30, 2017, and 2016, we made no contributions to our other postretirement benefit plans; we do not expect to make any contributions to our other postretirement benefit plans in 2017.

Commitments, Guarantees and Contingencies

9 Months Ended

Sep. 30, 2017

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 11. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our 2016 Form 10-K, with additional disclosure provided in the following paragraphs.

Square Butte PPA. Minnesota Power has a PPA with Square Butte 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 PSA. (See Minnkota Power PSA.) Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of September 30, 2017, Square Butte had total debt outstanding of $309.3 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 nine months ended September 30, 2017, was $60.6 million ($56.8 million for the nine months ended September 30, 2016). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $7.1 million ($7.2 million for the same period in 2016). 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 PSA. Minnesota Power has a PSA with Minnkota Power, which commenced in 2014. Under the PSA, 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 2017 and in 2016.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

Tenaska PPA. On May 10, 2017, Minnesota Power and an affiliate of Tenaska signed a long-term PPA that provides for Minnesota Power to purchase the energy and associated capacity from a 250 MW wind energy facility in southwest Minnesota for a 20-year period beginning in 2020. This agreement is 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, and a wind energy facility. (See Note 6. Regulatory Matters.) The agreement provides for the purchase of output from the facility at fixed energy prices. There are no fixed capacity charges, and Minnesota Power will only pay for energy as it is delivered.

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 2018 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 $7.2 million for the remainder of 2017, $29.0 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 during 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 2023. The aggregate amount of minimum lease payments for all operating leases is $3.4 million for the remainder of 2017, $12.0 million in 2018, $10.7 million in 2019, $7.5 million in 2020, $5.9 million in 2021 and $18.3 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.

Great Northern Transmission Line. As a condition of the 250-MW long-term PPA entered into 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.

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 Note 6. Regulatory Matters.) 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 $66.9 million have been incurred through September 30, 2017, of which $36.8 million has been recovered from a subsidiary of Manitoba Hydro.

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 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 expensed unless recoverable in rates from customers.

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

New Source Review (NSR). In 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 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 in 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. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as part of its EnergyForward strategic plan. We believe that costs to retire Boswell Units 1 and 2 will 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 certain states in the eastern half of the U.S., 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 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.

Minnesota Power’s generation levels and emission rates in 2015 and 2016 were below its allowances. Allowances for 2017 and 2018 were distributed in June 2016. Based on our review of the NO_x and SO₂ allowances issued and pending issuance, we currently expect generation levels and emission rates will result in compliance with the CSAPR.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Mercury and Air Toxics Standards (MATS) 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 2012, addressing such emissions from coal-fired utility units greater than 25 MW. 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, or April 2016 if granted an extension. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed in 2015. Investments and compliance work previously completed at Boswell Unit 3, including 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 2015 positioned those units for MATS compliance.

In 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 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. In April 2016, the EPA announced its determination that the MATS rule is appropriate and necessary, when also 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.)

Minnesota Mercury Emissions Reduction Act/Rule. In order to comply with the 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 2012. Major existing sources had until January 2016, to achieve compliance with the final rule and July 2016, to perform initial compliance demonstrations. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule and are currently in compliance. Compliance consisted largely of adjustments to our operating practices; therefore, the costs for complying with the final rule were not 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 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 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. As a result, 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 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 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by 2013, based on already available monitoring data, and issued designations of the 2012 revised primary annual fine particulate attainment status in 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. In September 2016, environmental groups filed a lawsuit against the EPA in the U.S. District Court for the Northern District of California alleging the EPA had failed to fully implement the PM_2.5standards in certain states, including Minnesota, by not enforcing states’ submittals of required infrastructure SIPs for the 2012 PM_2.5NAAQS. The outcome of this litigation is uncertain, and as such, any 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 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.

In 2013, the EPA provided guidance to states regarding implementation of the one-hour NO₂ NAAQS and in 2014, as clarified in 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. In 2015, the EPA published in the Federal Register an approval and partial disapproval of the 2014 SIP revision. According to the MPCA, the partial disapproval is regarding state delegation of a program unrelated to the one-hour NAAQS for SO₂ and NO_2,and is not expected to require further action. On July 16, 2017, the EPA proposed retaining the current one-hour and annual NO₂NAAQS. Additional compliance costs for the one-hour NO₂ NAAQS are not expected at this time.

In 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. In January 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. Compliance options include ambient monitoring, modeling existing enforceable emission limits, or modeling actual emissions. The MPCA initially informed Minnesota Power that compliant SO₂ modeling recently completed at these facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also requires facilities have federally-enforceable permit limits at which the one-hour SO₂NAAQS compliance was modeled by January 13, 2017. Taconite Harbor was issued an amended air permit in September 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 13, 2017, deadline to amend the Boswell permit. The MPCA is in discussions with the EPA on alternate compliance pathways to use existing completed modeling at current limits. On August 21, 2017, the EPA proposed retaining the current primary SO₂one-hour NAAQS. Compliance costs for the one-hour SO₂ NAAQS are not expected to be material.

Class I Air Quality Petitions and Requests. In 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. A public hearing was held by the Fond du Lac Band and the public comment period on the petition expired in 2014.

In 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 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 followed by public hearings and a public comment period ending in 2015.

The next step for the Fond du Lac Band and the Bad River Band would be 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 generating facilities;


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


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

Climate Action Plan (CAP). In 2015, the Federal government announced an updated 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. On March 28, 2017, President Trump signed an Executive Order titled Promoting Energy Independence and Economic Growth that rescinded the CAP.

EPA Regulation of GHG Emissions. In 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 may 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 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established higher permitting thresholds for GHG than for other pollutants subject to PSD; however, the court also upheld the EPA’s ability 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 October 2016, the EPA published a proposed rule in the Federal Register to revise its PSD and Title V regulatory provisions concerning GHG emissions. In this proposed rule, the EPA proposes to amend its regulations to clarify that a source’s obligation to obtain a PSD or Title V permit is triggered only by non-GHG pollutants. If the PSD or Title V permitting requirements are triggered by non-GHG, NSR pollutants, then these programs will also apply to the source’s GHG emissions. The proposed rule, as currently written, is not expected to have a material impact on the Title V permitting for current operations. It is uncertain how the Title V permitting requirements will be affected by the March 28, 2017, Executive Order titled Promoting Energy Independence and Economic Growth.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In 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 2015, together with a proposed federal implementation plan and a model rule for emissions trading. Petitions for review of the rule were filed with the U.S. Court of Appeals for the District of Columbia Circuit. In February 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In September 2016, the U.S. Court of Appeals for the District of Columbia heard oral arguments and is currently deliberating. The EPA is precluded from enforcing the CPP while the U.S. 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 constitutes 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. The regulatory review initiated by the March 28, 2017, Executive Order titled Promoting Energy Independence and Economic Growth is directed to include Section 111(b) and 111(d) CPP provisions. In addition, the EPA has filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in abeyance while the EPA is reviewing the rule. On October 10, 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. Minnesota Power continues to monitor the status of the CPP and related matters.

State goals under the CPP are expressed as both mass-based and rate-based, 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 original schedule for the CPP, each state would have been required to develop a SIP by September 2016, or by September 6, 2018, if granted an extension. Due to the U.S. Supreme Court order staying the effectiveness of the CPP, those SIP submittal dates are not currently in effect. If the CPP is upheld at the completion of the appellate court process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes.

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 additional costs through a rate proceeding.

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 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 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. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment indicates costs of compliance up to $15 million over the next five years. Minnesota Power would seek recovery of additional costs through a rate proceeding.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Steam Electric Power Generating Effluent Guidelines. In 2015, the EPA issued revised federal effluent limit guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It sets effluent limits and prescribes BACT for several wastewater streams, including flue gas desulphurization (FGD) water and coal combustion landfill leachate. On April 12, 2017, the EPA published in the Federal Register the postponement of certain compliance deadlines and formally announced that it would reconsider the final ELG rule. Under the ELG rule schedule, required compliance activity deadlines could have been in place as soon as November 1, 2018. These deadlines could have included prescriptive wastewater treatment technology installation, as well as a ban on bottom ash contact water discharges. If the EPA’s reconsideration results in the rule being revised or rescinded, the authority to regulate bottom ash transport water and FGD wastewater would fall under existing Effluent Guidelines Limits and state resource agency purview. On September 13, 2017, the EPA formally announced a two-year postponement of the ELG compliance date to November 1, 2020, while the agency reconsiders bottom ash transport water and FGD wastewater provisions.

We are evaluating the final ELG rule’s 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 reuse. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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

Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill which has been idled and has a temporary landfill cover in place, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.

The EPA issued the final coal combustion residuals (CCR) rule in 2014 under Subtitle D (non-hazardous) of RCRA and it was published in the Federal Register in 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. Recently, the EPA has indicated to Minnesota Power that the Taconite Harbor landfill is a CCR unit, based on the EPA’s interpretation of the CCR rule language. Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. On September 13, 2017, the EPA announced its intention to formally reconsider the CCR rule. Compliance costs, if any, for CCR at Taconite Harbor cannot be estimated at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Other Matters.

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 2018 and 2032. As of September 30, 2017, ALLETE Clean Energy has $15.4 million outstanding in standby letters of credit.

U.S. Water Services. As of September 30, 2017, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

BNI Energy. As of September 30, 2017, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6 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. BNI Energy’s total reclamation liability 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 September 30, 2017, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $8.6 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 September 30, 2017, we owned 70 percent of the assessable land in the Town Center District (72 percent at December 31, 2016) and 58 percent of the assessable land in the Palm Coast Park District (92 percent at December 31, 2016). At September 30, 2017, 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 $2.0 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

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes three operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services is our integrated water management company. 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.

NOTE 14. BUSINESS SEGMENTS (Continued)



	Quarter Ended					Nine Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
Millions
Operating Revenue
Regulated Operations	$277.6		$253.3			$824.1		$740.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	13.5		14.7			56.8		57.1
U.S. Water Services	40.2		37.8			110.7		104.5

Corporate and Other	31.2		43.8			89.8		96.1
Total Operating Revenue		$362.5		$349.6			$1,081.4		$998.2
Net Income (Loss) Attributable to ALLETE
Regulated Operations		$34.2		$45.0			$110.1		$110.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	0.6		1.0			11.1		9.7
U.S. Water Services	1.3		1.5			1.6		2.0

Corporate and Other	8.8		(7.2		)	8.0		(10.7		)
Total Net Income Attributable to ALLETE		$44.9		$40.3			$130.8		$111.0



	September 30, 2017		December 31, 2016
Millions
Assets
Regulated Operations	$3,811.7		$3,823.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	560.3		566.0
U.S. Water Services	293.3		264.1

Corporate and Other	313.2		222.9
Total Assets		$4,978.5		$4,876.9

Operations and Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Inventories – Net [Policy Text Block]	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.
Subsequent Events [Policy Text Block]	The Company performed an evaluation of subsequent events for potential recognition and disclosure through the date of the financial statements issuance.
New Accounting Standards [Policy Text Block]	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. 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 September 30, 2017, the Company has reviewed all of its revenue streams and contracts for its regulated businesses, completing the preliminary evaluations of the impact of this guidance. Based on this review, the Company does not expect the guidance to materially affect the results of its regulated operations, which represent the majority of revenue. Our review and analysis of the Company’s energy infrastructure and related services and corporate and other businesses is in progress and we similarly do not expect the guidance to impact the results of these businesses. Management continues to evaluate the need for additional disclosures to meet the requirements of the new standard following adoption. The Company will adopt and implement the new guidance on a modified retrospective basis which requires application of standards to all contracts with customers effective January 1, 2018, with the cumulative impact on contracts with performance obligations not yet satisfied as of December 31, 2017, recognized as an adjustment to retained earnings on the Consolidated Balance Sheet. 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 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 adoption of 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. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.
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 impairment was recorded for the quarter and nine months ended September 30, 2017, and 2016.
Available-for-sale Investments [Policy Text Block]	We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities.
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 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. The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as shown in the following table. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to working capital; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.
Fair Value Measurement [Policy Text Block]	Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate. 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. 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.
North Dakota Investment Tax Credits [Policy Text Block]	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 Corporate and Other operations.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.
Equity Method Investments [Policy Text Block]	We account for our investment in ATC under the equity method of accounting.
Income Tax [Policy Text Block]	The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate, and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.
Uncertain Tax Positions [Policy Text Block]	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.
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 and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the nine months ended September 30, 2017, and 2016, no options to purchase shares of ALLETE common stock were excluded from the computation of diluted earnings per share.
Power Purchase Agreements [Policy Text Block]	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.
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 expensed unless recoverable in rates from customers.
Business Segments [Policy Text Block]	We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Operations and Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Inventories – Net [Table Text Block]



Inventories – Net	September 30, 2017			December 31, 2016
Millions
Fuel (a)		$39.6			$43.9
Materials and Supplies	48.2			48.7
Raw Materials	2.9			2.9
Work in Progress	3.5			1.0
Finished Goods	9.4			8.6
Reserve for Obsolescence	(1.0		)	(0.9		)
Total Inventories – Net		$102.6			$104.2


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

Prepayments and Other Current Assets [Table Text Block]



Prepayments and Other Current Assets	September 30, 2017		December 31, 2016
Millions
Deferred Fuel Adjustment Clause		$20.2		$18.6
Restricted Cash	6.5		2.2
Other	17.5		19.5
Total Prepayments and Other Current Assets		$44.2		$40.3

Other Non-Current Assets [Table Text Block]



Other Non-Current Assets	September 30, 2017		December 31, 2016
Millions
Contract Payment		$28.0		$29.6
Finance Receivable	11.0		11.5
Restricted Cash	8.6		8.6
Other	55.4		56.8
Total Other Non-Current Assets		$103.0		$106.5

Other Current Liabilities [Table Text Block]



Other Current Liabilities	September 30, 2017		December 31, 2016
Millions
PSAs		$24.8		$24.6
Other	59.9		49.1
Total Other Current Liabilities		$84.7		$73.7

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities	September 30, 2017		December 31, 2016
Millions
Asset Retirement Obligation		$157.4		$136.6
PSAs	95.3		113.8
Contingent Consideration (a)	5.6		25.0
Other	42.8		47.3
Total Other Non-Current Liabilities		$301.1		$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 [Table Text Block]

Supplemental Statement of Cash Flows Information.



Nine Months Ended September 30,	2017		2016
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$51.4		$54.9
Cash Paid During the Period for Income Taxes		$0.4		$0.5
Noncash Investing and Financing Activities
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	$1.2		$(19.5)
Capitalized Asset Retirement Costs		$19.7		$3.7
AFUDC–Equity		$0.7		$1.7
ALLETE Common Stock Contributed to the Pension Plans		$13.5	—
ALLETE Common Stock Received for Land Inventory	—			$8.0
Long-Term Finance Receivable for Land Inventory	—			$12.0

Acquisitions (Table)

9 Months Ended

Sep. 30, 2017

Tonka Water [Member]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$1.6
Accounts Receivable	5.1
Other Current Assets	4.4
Trade Names (a)	0.9
Goodwill (a)(b)	18.5
Other Non-Current Assets	0.2
Total Assets Acquired		$30.7
Liabilities Assumed
Current Liabilities		$10.6
Non-Current Liabilities	0.7
Total Liabilities Assumed		$11.3
Net Identifiable Assets Acquired		$19.4

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


(b)	Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill.

Water & Energy Systems Technology [Member]

Schedule of Business Acquisitions [Table Text Block]



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.

Goodwill and Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets [Table Text Block]

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



	December 31, 2016		Additions (a)		Amortization	September 30, 2017
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	$59.3		—		$(3.4)		$55.9
Developed Technology and Other (b)	6.3			$0.9	(0.7)	6.5
Total Definite-Lived Intangible Assets	65.6		0.9		(4.1)	62.4
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		—		n/a	16.6
Total Intangible Assets		$82.2		$0.9	$(4.1)		$79.0


(a)	Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 3. Acquisitions.)


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

Fair Value (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of September 30, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$10.9	—		—			$10.9
Available-for-sale – Corporate and Governmental Debt Securities	—			$10.1	—		10.1
Cash Equivalents	2.2		—		—		2.2
Total Fair Value of Assets		$13.1		$10.1	—			$23.2

Liabilities (b)
Deferred Compensation	—			$18.7	—			$18.7
U.S. Water Services Contingent Consideration	—		—			$5.6	5.6
Total Fair Value of Liabilities	—			$18.7		$5.6		$24.3
Total Net Fair Value of Assets (Liabilities)		$13.1	$(8.6)		$(5.6)		$(1.1)


(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.

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2016		$25.0
Accretion	0.7
Payments (a)	(19.7		)
Changes in Cash Flow Projections (a)	(0.4		)
Balance as of September 30, 2017		$5.6


(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, and were paid in the first half of 2017.

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
September 30, 2017	$1,519.0	$1,627.9
December 31, 2016	$1,569.1	$1,653.8

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2017

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	September 30, 2017		December 31, 2016
Millions
Current Regulatory Assets
Deferred Fuel Adjustment Clause		$20.2		$18.6
Total Current Regulatory Assets	20.2		18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans	221.4		226.1
Income Taxes (a)	35.7		33.8
Asset Retirement Obligations	29.8		26.0
Cost Recovery Riders	5.2		30.5
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	4.9		4.0
Other	8.6		4.7
Total Non-Current Regulatory Assets	310.6		330.1
Total Regulatory Assets		$330.8		$348.7

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$57.0		$56.8
Plant Removal Obligations	19.2		19.1
Income Taxes	18.6		19.1
North Dakota Investment Tax Credits	13.9		28.2
Other	2.8		2.6
Total Non-Current Regulatory Liabilities		$111.5		$125.8


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

Income Tax Expense (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Millions
Current Income Tax Expense (a)
Federal	—			—			—			—
State		$0.1		—				$0.3		$0.2
Total Current Income Tax Expense		$0.1		—				$0.3		$0.2
Deferred Income Tax Expense
Federal	$9.2				$0.4		$20.3				$7.1
State	5.0			1.4			14.5			8.9
Investment Tax Credit Amortization	(0.1		)	(0.1		)	(0.5		)	(0.5		)
Total Deferred Income Tax Expense	$14.1				$1.7		$34.3				$15.5
Total Income Tax Expense	$14.2				$1.7		$34.6				$15.7


(a)	For the quarter and nine months ended September 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.

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



	Quarter Ended						Nine Months Ended
Reconciliation of Taxes from Federal Statutory	September 30,						September 30,
Rate to Total Income Tax Expense	2017			2016			2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$59.1			$42.0			$165.4			$127.2
Statutory Federal Income Tax Rate	35		%	35		%	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$20.7			$14.7			$57.9			$44.5
Increase (Decrease) in Income Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	3.3			0.9			9.6			5.9
Production Tax Credits	(10.4		)	(14.0		)	(33.4		)	(34.5		)
Other	0.6			0.1			0.5			(0.2		)
Total Income Tax Expense		$14.2			$1.7			$34.6			$15.7

Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

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



	Pension						Other Postretirement
Components of Net Periodic Benefit Cost (Income)	2017			2016			2017			2016
Millions
Quarter Ended September 30,
Service Cost		$2.6			$2.0			$1.1			$1.0
Interest Cost	8.1			8.2			2.0			1.9
Expected Return on Plan Assets	(10.6		)	(10.7		)	(2.6		)	(2.8		)
Amortization of Prior Service Credits	—			—			(0.5		)	(0.7		)
Amortization of Net Loss	2.5			2.4			—			—
Net Periodic Benefit Cost (Income)		$2.6			$1.9		—			$(0.6)

Nine Months Ended September 30,
Service Cost		$7.7			$6.1			$3.3			$3.0
Interest Cost	24.4			24.4			5.8			5.6
Expected Return on Plan Assets	(31.8		)	(32.0		)	(7.9		)	(8.4		)
Amortization of Prior Service Credits	—			—			(1.5		)	(2.2		)
Amortization of Net Loss	7.4			7.3			0.2			0.1
Net Periodic Benefit Cost (Income)		$7.7			$5.8		$(0.1)			$(1.9)

Business Segments (Tables)

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Business Segments [Table Text Block]



	Quarter Ended					Nine Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
Millions
Operating Revenue
Regulated Operations	$277.6		$253.3			$824.1		$740.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	13.5		14.7			56.8		57.1
U.S. Water Services	40.2		37.8			110.7		104.5

Corporate and Other	31.2		43.8			89.8		96.1
Total Operating Revenue		$362.5		$349.6			$1,081.4		$998.2
Net Income (Loss) Attributable to ALLETE
Regulated Operations		$34.2		$45.0			$110.1		$110.0

Energy Infrastructure and Related Services
ALLETE Clean Energy	0.6		1.0			11.1		9.7
U.S. Water Services	1.3		1.5			1.6		2.0

Corporate and Other	8.8		(7.2		)	8.0		(10.7		)
Total Net Income Attributable to ALLETE		$44.9		$40.3			$130.8		$111.0



	September 30, 2017		December 31, 2016
Millions
Assets
Regulated Operations	$3,811.7		$3,823.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	560.3		566.0
U.S. Water Services	293.3		264.1

Corporate and Other	313.2		222.9
Total Assets		$4,978.5		$4,876.9

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

Sep. 30, 2017

Dec. 31, 2016

Inventories – Net [Abstract]

Fuel

^[1]

$ 39.6

$ 43.9

Materials and Supplies

48.2

48.7

Raw Materials

2.9

Work in Progress

3.5

1.0

Finished Goods

9.4

8.6

Reserve for Obsolescence

(1.0)

(0.9)

Total Inventories – Net

102.6

104.2

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

20.2

18.6

Restricted Cash

6.5

2.2

Total Prepayments and Other Current Assets

17.5

19.5

44.2

40.3

Other Non-Current Assets [Abstract]

Contract Payment

28.0

29.6

Finance Receivable

11.0

11.5

Restricted Cash

8.6

Total Other Non-Current Assets

55.4

56.8

103.0

106.5

Other Current Liabilites [Abstract]

PSAs

24.8

24.6

Total Other Current Liabilities

59.9

49.1

84.7

73.7

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

157.4

136.6

PSAs

95.3

113.8

Contingent Consideration

^[2]

5.6

25.0

Total Other Non-Current Liabilities

42.8

47.3

$ 301.1

$ 322.7

[1]	Fuel consists primarily of coal inventory at Minnesota Power.
[2]	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.)

Operations and Significant Accounting Policies - Supplemental Statement of Cash Flows Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$ 51.4	$ 54.9
Cash Paid During the Period for Income Taxes	0.4	0.5
Noncash Investing and Financing Activities [Abstract]
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment	1.2	(19.5)
Capitalized Asset Retirement Costs	19.7	3.7
AFUDC–Equity	0.7	1.7
ALLETE Common Stock Contributed to the Pension Plans	13.5	0.0
ALLETE Common Stock Received for Land Inventory [Member]
Noncash Consideration for Land Inventory [Line Items]
Consideration for Land Inventory	0.0	8.0
Long-Term Finance Receivable for Land Inventory [Member]
Noncash Consideration for Land Inventory [Line Items]
Consideration for Land Inventory	$ 0.0	$ 12.0

Operations and Significant Accounting Policies - New Accounting Pronouncements (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Improvements to Employee Share-Based Payment Accounting [Member] \| Income Tax Expense (Benefit) [Member] \| Maximum [Member]
New Accounting Pronouncements [Line Items]
Impact of Adoption Annually	$ 1

Operations and Significant Accounting Policies - Revision of Prior Balance Sheet (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Regulatory Assets [Member]
Revision of Prior Balance Sheet [Line Items]
Immaterial Revision	$ 29.5
Deferred Income Taxes [Member]
Revision of Prior Balance Sheet [Line Items]
Immaterial Revision	$ 29.5

Operations and Significant Accounting Policies - Reclassification of Prior Income Statement (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Operating Revenue to Operating Revenue – Utility [Member]
Reclassification of Prior Income Statement [Line Items]
Prior Period Reclassification Amount	$ 253.3	$ 740.5
Operating Revenue to Operating Revenue – Non-utility [Member]
Reclassification of Prior Income Statement [Line Items]
Prior Period Reclassification Amount	96.3	257.7
Cost of Sales to Fuel, Purchased Power and Gas – Utility [Member]
Reclassification of Prior Income Statement [Line Items]
Prior Period Reclassification Amount	$ 0.7	$ 4.6

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2016

Available-for-sale Securities

ALLETE Properties

$ 28.8

$ 31.7

21.0

^[1]

21.0

^[1]

18.8

2.2

1.3

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

3.8

Total Other Investments

55.8

$ 55.6

One Year or Less

1.1

One Year to Less Than Three Years

3.2

Three Years to Less Than Five Years

4.2

Five or More Years

1.6

Impairment of Land Inventory

$ 0.0

[1]

As of September 30, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.1 million, in one year to less than three years was $3.2 million, in three years to less than five years was $4.2 million and in five or more years was $1.6 million.

Acquisitions (Details)	9 Months Ended	12 Months Ended
Acquisitions (Details)	Sep. 30, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Reason for Business 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 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.

Acquisitions - Tonka Water (Details) - USD ($)
$ in Millions

Sep. 01, 2017

Sep. 30, 2017

Dec. 31, 2016

$ 149.9

$ 131.2

Tonka Water [Member]

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Tonka Water

Total Consideration

$ 19.4

Cash Payment to Acquire Business

19.0

Payments Due in Fourth Quarter 2017

0.4

Cash and Cash Equivalents

1.6

Accounts Receivable

5.1

Other Current Assets

4.4

Trade Names

^[1]

0.9

Total Liabilities Assumed

^[1],[2]

18.5

Other Non-Current Assets

0.2

Total Assets Acquired

30.7

Liabilities Assumed [Abstract]

Current Liabilities

10.6

Non-Current Liabilities

0.7

11.3

Net Identifiable Assets Acquired

19.4

Tax Deductible Goodwill

$ 4.1

[1]	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 4. Goodwill and Intangible Assets.)
[2]	Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill.

Acquisitions - Acquisition of Non-Controlling Interest (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Apr. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Acquisition of Non-Controlling Interest [Line Items]
Payment to Acquire Non-Controlling Interest		$ 0.0	$ 8.0
ALLETE Clean Energy [Member]
Acquisition of Non-Controlling Interest [Line Items]
Payment to Acquire Non-Controlling Interest	$ 8.0
Gain or Loss in Net Income or Other Comprehensive Income	$ 0.0

Acquisitions - WEST (Details) - USD ($)
$ in Millions

1 Months Ended

6 Months Ended

Oct. 31, 2016

Jun. 30, 2017

Sep. 30, 2017

Dec. 31, 2016

Water & Energy Systems Technology [Member]

$ 149.9

$ 131.2

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Water & Energy Systems Technology of Nevada, Inc.

Total Consideration

$ 6.7

Cash Payment to Acquire Business

5.9

Working Capital Adjustments

$ 0.2

Payment Due in April 2018

0.6

Cash and Cash Equivalents

0.1

Other Current Assets

1.0

Customer Relationships

^[1]

2.8

Total Liabilities Assumed

^[1],[2]

4.2

Other Non-Current Assets

0.1

Total Assets Acquired

8.2

Liabilities Assumed [Abstract]

Current Liabilities

0.3

Non-Current Liabilities

1.2

1.5

Net Identifiable Assets Acquired

6.7

Tax Deductible Goodwill

$ 0.0

[1]	Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 4. Goodwill and Intangible Assets.)
[2]	For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2016

Definite-Lived Intangible Assets [Roll Forward]

$ 65.6

^[1]

0.9

Amortization

$ (1.3)

(4.1)

$ (3.8)

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

62.4

Accumulated Amortization

13.4

$ 9.3

1.5

5.3

4.9

4.7

4.6

41.4

Intangible Assets [Abstract]

Total Intangible Assets

79.0

$ 82.2

Total Intangible Assets, Additions

^[2]

0.9

Total Intangible Assets, Amortization

(1.3)

$ (1.3)

$ (4.1)

$ (3.8)

Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Trademarks and Trade Names [Member]

19 years

Indefinite-Lived Intangible Assets [Roll Forward]

$ 16.6

^[2]

0.0

Customer Relationships [Member]

16.6

Definite-Lived Intangible Assets [Roll Forward]

59.3

^[2]

0.0

Amortization

(3.4)

55.9

$ 55.9

Total Intangible Assets, Amortization

20 years

Intangible Assets [Abstract]

$ (3.4)

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

^[1]

6.3

^[1],[2]

0.9

Amortization

^[1]

(0.7)

Total Intangible Assets, Amortization

^[1]

$ 6.5

6.5

Intangible Assets [Abstract]

^[1]

$ (0.7)

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

Definite-Lived Intangible Assets [Roll Forward]

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

1 year

Definite-Lived Intangible Assets [Roll Forward]

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

11 years

Definite-Lived Intangible Assets [Roll Forward]

7 years

[1]	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names.
[2]	Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 3. Acquisitions.)

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

9 Months Ended

12 Months Ended

Sep. 30, 2017

Dec. 31, 2016

Recurring Fair Value Measures [Member]

$ 2.2

$ 1.3

Available-for-sale – Corporate and Governmental Debt Securities

10.9

^[1]

7.1

^[2]

10.1

^[1]

11.7

^[2]

2.2

^[1]

1.3

^[2]

23.2

20.1

18.7

^[3]

16.0

^[4]

5.6

^[3]

25.0

^[4]

24.3

41.0

Fair Value Hierarchy Transfers, All Levels

(1.1)

(20.9)

0.0

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

Available-for-sale – Corporate and Governmental Debt Securities

10.9

^[1]

7.1

^[2]

0.0

^[1]

0.0

^[2]

2.2

^[1]

1.3

^[2]

13.1

8.4

0.0

^[3]

0.0

^[4]

0.0

^[3]

0.0

^[4]

0.0

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

13.1

8.4

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[1]

0.0

^[2]

10.1

^[1]

11.7

^[2]

0.0

^[1]

0.0

^[2]

10.1

11.7

18.7

^[3]

16.0

^[4]

0.0

^[3]

0.0

^[4]

18.7

16.0

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

(8.6)

(4.3)

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[1]

0.0

^[2]

0.0

^[1]

0.0

^[2]

0.0

^[1]

0.0

^[2]

0.0

0.0

^[3]

0.0

^[4]

5.6

^[3]

25.0

^[4]

5.6

25.0

(5.6)

(25.0)

25.0

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

5.6

$ 25.0

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

Activity in Level 3

0.7

Recurring Fair Value Measures [Member] | Level 3 [Member] | Changes in Cash Flow Projections [Member]

Activity in Level 3

^[5]

(19.7)

Activity in Level 3

$ (0.4)

[1]	Included in Other Investments on the Consolidated Balance Sheet.
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[5]	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, and were paid in the first half of 2017.

Fair Value - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,519.0	$ 1,569.1
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,627.9	$ 1,653.8

Fair Value - Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2016
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Abstract]
Indicators of Impairment	$ 0.0	$ 0.0	$ 0.0

Regulatory Matters - Electric Rates (Details) $ in Millions			1 Months Ended			3 Months Ended		9 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Aug. 09, 2017 USD ($)	Apr. 13, 2017 USD ($)	Dec. 31, 2016 USD ($)	Nov. 30, 2016 USD ($)	Jun. 30, 2016	Sep. 30, 2017 USD ($) Customers Years MW	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) Customers Years MW	Sep. 30, 2016 USD ($)
PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity	10.50%
Approved Equity Ratio	55.00%
Requested Average Rate Increase					3.10%
Requested Return on Equity					10.90%
Requested Equity Ratio					55.00%
Revenue Increase (Decrease) from Approved Rate	$ 2.5
Approved Rate Increase (Decrease)	2.90%
Electric Rates [Member] \| MPUC [Member] \| 2010 Minnesota Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [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 Customers [Member]
Regulatory Matters [Line Items]
Revenue from Cost Recovery Riders						$ 23.1	$ 25.1	$ 71.7	$ 73.9
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase				9.00%
Requested Return on Equity				10.25%
Requested Equity Ratio				53.81%
Annual Additional Revenue Generated from Requested Final Rate Increase				$ 55.0
Annual Additional Revenue Generated from Requested Interim Rate Increase		$ 32.2	$ 34.7	49.0
Annual Additional Revenue Generated from Requested Final Rate Increase, Amended								$ 49.0
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Boswell Energy Center [Member]
Regulatory Matters [Line Items]
Expected Decrease in Annual Depreciation Expense				$ 25.0
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Retail Customers [Member] \| Corporate and Other [Member]
Regulatory Matters [Line Items]
After-Tax (Increase) Decrease for North Dakota Investment Tax Credits						(8.0)	9.0
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Sales [Member]
Regulatory Matters [Line Items]
Revenue Increase (Decrease) from Approved Rate						$ 14.0	$ (15.0)
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		16
Notice Required to Terminate (Years) \| Years						3		3
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]
Average Monthly Demand (MW) \| MW						29		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		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		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%		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%)		(1.00%)
Electric Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase (Decrease)	3.80%
Natural Gas Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase (Decrease)	(4.80%)
Water Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Rate Increase (Decrease)	9.80%

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - MW	Jul. 28, 2017	Sep. 30, 2017	Dec. 31, 2015
Resource Package [Member] \| Tenaska PPA [Member] \| Wind Turbine Generators [Member] \| Tenaska [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)		250
Resource Package [Member] \| Minimum [Member] \| Natural Gas PPA [Member] \| Natural Gas-fired [Member] \| Jointly Owned by ALLETE and Dairyland Power Cooperative [Member] \| Combined-Cycle Natural Gas-fired Generating Facility [Member] \| Jointly Owned Electricity Generation Plant [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Jointly Owned (MW)	525	525
Resource Package [Member] \| Maximum [Member] \| Natural Gas PPA [Member] \| Natural Gas-fired [Member] \| Jointly Owned by ALLETE and Dairyland Power Cooperative [Member] \| Combined-Cycle Natural Gas-fired Generating Facility [Member] \| Jointly Owned Electricity Generation Plant [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Jointly Owned (MW)	550	550
Minnesota Power [Member] \| Integrated Resource Plan [Member] \| Minimum [Member] \| Natural Gas-fired [Member]
Regulatory Matters [Line Items]
Additional Natural Gas-fired Generation (MW)			200
Minnesota Power [Member] \| Integrated Resource Plan [Member] \| Maximum [Member] \| Natural Gas-fired [Member]
Regulatory Matters [Line Items]
Additional Natural Gas-fired Generation (MW)			300
Minnesota Power [Member] \| Resource Package [Member] \| Tenaska PPA [Member] \| Wind Turbine Generators [Member] \| Tenaska [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)	250
Minnesota Power [Member] \| Resource Package [Member] \| Solar Energy PPA [Member] \| Solar Energy Generation [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)	10
Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Long-Term Contract for Purchase of Electric Power, Share of Plant Output to be Purchased (MW)	250
Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member] \| Natural Gas-fired [Member]
Regulatory Matters [Line Items]
Expected Output Entitlement	50.00%

Regulatory Matters - Great Northern Transmission Line (Details) - Great Northern Transmission Line [Member] $ in Millions	Sep. 30, 2017 USD ($) kV Miles
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500
Total Project Costs Incurred to Date	$ 66.9
Minimum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	560.0
Maximum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	710.0
Minnesota Power [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	300.0
Minnesota Power [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Total Project Cost in the U.S.	350.0
Manitoba Hydro [Member]
Regulatory Matters [Line Items]
Project Costs Recovered from Counterparty	$ 36.8
MPUC [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 (Details) - MPUC [Member] - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017
Minimum [Member]
Regulatory Matters [Line Items]
CIP Spending Requirement			1.50%
CIP Annual Filing [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Financial Incentive	$ 5.5	$ 7.5

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Sep. 30, 2017
Return on Equity Complaint 1 [Member]
Loss Contingencies [Line Items]
Requested Return on Equity Filed with the FERC by Third Party	9.15%
FERC Authorized Return on Common Equity	10.32%
FERC Authorized Return on Equity Including Incentive Adder	10.82%
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%
Proposed Return on Equity by Federal Administrative Law Judge Including Incentive Adder	10.20%

Regulatory Matters - Minnesota Solar Energy Standard (Details) - MPUC [Member]	Sep. 30, 2017 MW
Minimum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
Minnesota Solar Energy Standard - Small Scale Solar Mandate Percentage	10.00%
Maximum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.04
Minnesota Solar Energy Standard [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - 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 Owned (MW)	10
Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	1
Minnesota Solar Energy Standard - Community Solar Garden Project - Owned and Operated [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	0.04

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

9 Months Ended

Sep. 30, 2017

Dec. 31, 2016

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

Current Regulatory Assets

$ 20.2

$ 18.6

310.6

330.1

Total Regulatory Assets

330.8

348.7

Wholesale and Retail Contra AFUDC [Member]

111.5

125.8

Plant Removal Obligations [Member]

57.0

56.8

19.2

19.1

Income Taxes [Member]

North Dakota Investment Tax Credits [Member]

18.6

19.1

Deferred Fuel Adjustment Clause [Member]

13.9

28.2

Current Regulatory Assets

20.2

18.6

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

221.4

226.1

Income Taxes [Member]

Asset Retirement Obligations [Member]

^[1]

35.7

33.8

Cost Recovery Riders [Member]

29.8

26.0

PPACA Income Tax Deferral [Member]

5.2

30.5

Conservation Improvement Program [Member]

5.0

4.9

4.0

8.6

4.7

Current Income Tax Expense [Abstract]

$ 2.8

$ 2.6

[1]	See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

Investment in ATC (Details) $ in Millions		3 Months Ended		9 Months Ended
Investment in ATC (Details) $ in Millions	Oct. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2016				$ 135.6
Cash Investments				6.6	$ 3.5
Equity in ATC Earnings		$ 5.9	$ 6.1	17.3	$ 15.0
Equity Investment Balance as of September 30, 2017		$ 146.0		$ 146.0
FERC [Member] \| Return on Equity Complaint 2 [Member]
ALLETE's Investment in ATC [Roll Forward]
Proposed Return on Equity		9.70%		9.70%
Proposed Return on Equity, Including Incentive Adder		10.20%		10.20%
ATC [Member]
Investment in ATC [Line Items]
Ownership Percentage		8.00%		8.00%
Expected Additional Investment in 2017		$ 0.0		$ 0.0
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2016				135.6
Cash Investments				6.6
Equity in ATC Earnings				17.3
Distributed ATC Earnings				(13.5)
Equity Investment Balance as of September 30, 2017		$ 146.0		$ 146.0
Authorized Return on Equity		10.32%	12.20%	10.32%	12.20%
Authorized Return on Equity, Including Incentive Adder		10.82%		10.82%
ATC [Member] \| Sensitivity Analysis [Member]
ALLETE's Investment in ATC [Roll Forward]
Basis Point Reduction on Approved Rate of Return on Common Equity		50		50
ATC [Member] \| Sensitivity Analysis [Member] \| After-tax [Member]
ALLETE's Investment in ATC [Roll Forward]
Annual Effect on Future Equity Earnings in ATC				$ 0.5
ATC [Member] \| Subsequent Event [Member]
ALLETE's Investment in ATC [Roll Forward]
Cash Investments	$ 1.2

Short-Term and Long-Term Debt (Details) - USD ($) $ in Millions	Aug. 25, 2017	Jun. 01, 2017	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Short-Term Debt - Principal			$ 64.6	$ 188.3
Short-Term Debt - Unamortized Debt Issuance Costs			(0.5)	(0.6)
Short-Term Debt - Total			64.1	187.7
Long-Term Debt - Principal			1,454.4	1,380.8
Long-Term Debt - Unamortized Debt Issuance Costs			(9.8)	(10.4)
Long-Term Debt - Total			1,444.6	1,370.4
Total Debt - Principal			1,519.0	1,569.1
Total Debt - Unamortized Debt Issuance Costs			(10.3)	(11.0)
Total Debt - Total			$ 1,508.7	$ 1,558.1
ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-Term Debt		$ 80.0
Interest Rate		3.11%
ALLETE Term Loan Variable Rate Due 2020 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-Term Debt	$ 40.0
Interest Rate - Basis	LIBOR
Interest Rate - Spread	1.025%

Short-Term and Long-Term Debt - Financial Covenants (Details)	Sep. 30, 2017
Debt Instrument [Line Items]
Actual Ratio of Indebtedness to Total Capitalization	0.42
Maximum [Member]
Debt Instrument [Line Items]
Required Ratio of Indebtedness to Total Capitalization	0.65

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

3 Months Ended

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Dec. 31, 2016

Federal

^[1]

$ 0.0

State

^[1]

0.1

0.0

0.3

0.2

Total Current Income Tax Expense

0.1

0.0

0.3

0.2

Deferred Income Tax Expense [Abstract]

Federal

9.2

0.4

20.3

7.1

State

5.0

1.4

14.5

8.9

Investment Tax Credit Amortization

(0.1)

(0.5)

Total Deferred Income Tax Expense

14.1

1.7

34.3

15.5

Total Income Tax Expense

14.2

1.7

34.6

15.7

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

Income Before Non-Controlling Interest and Income Taxes

$ 59.1

$ 42.0

$ 165.4

$ 127.2

Statutory Federal Income Tax Rate

35.00%

Income Taxes Computed at 35 percent Statutory Federal Rate

$ 20.7

$ 14.7

$ 57.9

$ 44.5

Increase (Decrease) in Tax Due to: [Abstract]

State Income Taxes – Net of Federal Income Tax Benefit

3.3

0.9

9.6

5.9

Production Tax Credits

(10.4)

(14.0)

(33.4)

(34.5)