Acquisitions [Text Block]

Investments [Text Block]

INVESTMENTS

Investments. As of March 31, 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	March 31, 2017		December 31, 2016
Millions
ALLETE Properties		$31.6		$31.7
Available-for-sale Securities (a)	19.6		18.8
Cash Equivalents	2.6		1.3
Other	3.9		3.8
Total Other Investments		$57.7		$55.6


(a)	As of March 31, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $3.0 million, in three years to less than five years was $5.0 million and in five or more years was $3.9 million.

Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairment was recorded for the three months ended March 31, 2017, and 2016.

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

Gross realized and unrealized gains and losses on our available-for-sale investments were immaterial for the three months ended March 31, 2017, and 2016.

Acquisitions

3 Months Ended

Mar. 31, 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 three months ended March 31, 2016.

2016 Activity.

Acquisition of Non-Controlling Interest. In April 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns the Condon wind energy facility for $8.0 million. This transaction was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income. As a result of the acquisition, the Condon wind energy facility is now 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 $6.5 million, subject to a working capital adjustment. Consideration of $5.9 million was paid in cash on the acquisition date 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 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.



Millions
Assets Acquired
Cash and Cash Equivalents		$0.1
Other Current Assets	1.1
Customer Relationships (a)	2.8
Goodwill (a)(b)	3.9
Other Non-Current Assets	0.1
Total Assets Acquired		$8.0
Liabilities Assumed
Current Liabilities		$0.2
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.4
Net Identifiable Assets Acquired		$6.6


(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 Disclosure [Abstract]

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

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+ Details

Goodwill and Intangible Assets

3 Months Ended

Mar. 31, 2017

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The aggregate carrying amount of goodwill was $131.2 million as of March 31, 2017, and December 31, 2016. There have been no changes to goodwill by reportable segment for the three months ended March 31, 2017.

Balances of intangible assets, net, excluding goodwill as of March 31, 2017, are as follows:



	December 31, 2016		Amortization	March 31, 2017
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships	$59.3		$(1.1)		$58.2
Developed Technology and Other (a)	6.3		(0.3)	6.0
Total Definite-Lived Intangible Assets	65.6		(1.4)	64.2
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		n/a	16.6
Total Intangible Assets		$82.2	$(1.4)		$80.8


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

Customer relationships have a remaining useful life of approximately 21 years, and developed technology and other have remaining useful lives ranging from approximately 2 years to approximately 12 years (weighted average of approximately 8 years). The weighted average remaining useful life of all definite-lived intangible assets as of March 31, 2017, is approximately 20 years.

Amortization expense of intangible assets was $1.4 million for the three months ended March 31, 2017 ($1.3 million for the three months ended March 31, 2016). Accumulated amortization was $10.7 million as of March 31, 2017 ($9.3 million as of December 31, 2016). The estimated amortization expense for definite‑lived intangible assets for the remainder of 2017 is $4.1 million. Estimated annual amortization expense for definite‑lived intangible assets is $5.1 million in 2018, $4.8 million in 2019, $4.5 million in 2020, $4.4 million in 2021 and $41.3 million thereafter.

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

3 Months Ended

Mar. 31, 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 March 31, 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.

NOTE 5. FAIR VALUE (Continued)



	Fair Value as of March 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.5	—		—			$7.5
Available-for-sale – Corporate and Governmental Debt Securities	—			$12.1	—		12.1
Cash Equivalents	2.6		—		—		2.6
Total Fair Value of Assets		$10.1		$12.1	—			$22.2

Liabilities (b)
Deferred Compensation	—			$17.2	—			$17.2
U.S. Water Services Contingent Consideration	—		—			$10.0	10.0
Total Fair Value of Liabilities	—			$17.2		$10.0		$27.2
Total Net Fair Value of Assets (Liabilities)		$10.1	$(5.1)		$(10.0)		$(5.0)


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


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet with the exception of the current portion of the U.S. Water Services Contingent Consideration which is included in Other Current Liabilities. (See Note 1. Operations and Significant Accounting Policies.)



	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 changes in discount rates, timing of milestones that trigger payment, and 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 March 31, 2017. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.

NOTE 5. FAIR VALUE (Continued)



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2016		$25.0
Accretion	0.5
Payments (a)	(15.1		)
Changes in Cash Flow Projections (b)	(0.4		)
Balance as of March 31, 2017		$10.0


(a)	Payments relate to retirement of U.S. Water Services former employees.

(b)

Changes in cash flow projections reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, which were paid in April 2017, resulting in $4.6 million of the U.S. Water Services Contingent Consideration liability being classified in Other Current Liabilities on the Consolidated Balance Sheet. The remaining liability will be paid through the first quarter of 2019.

For the three months ended March 31, 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
March 31, 2017	$1,543.4	$1,614.9
December 31, 2016	$1,569.1	$1,653.8

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized. For the three months ended March 31, 2017, and the year ended December 31, 2016, there were no triggering events or indicators of impairment for these non-financial assets.

Regulatory Matters [Text Block]

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

+ References + Details

Regulatory Matters

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

REGULATORY MATTERS

Regulatory matters are summarized in Note 4. Regulatory Matters to our Consolidated Financial Statements in our 2016 Form 10‑K, with additional disclosure provided in the following paragraphs.

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

2010 Minnesota General Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $24.2 million for the three months ended March 31, 2017 ($25.4 million for the three months ended March 31, 2016).

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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 53.8 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. On February 28, 2017, Minnesota Power filed an update to its rate increase request, reducing its requested final retail rate increase from approximately $55 million to approximately $39 million on an annualized basis. As of March 31, 2017, Minnesota Power has not received any indication that a refund of interim rates will be necessary. Management will continue to evaluate the need for a reserve for interim rates as the 2016 general rate case proceeds.

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

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

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

In 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. No termination notice may be given for this contract prior to June 30, 2025. The electric service agreements with SWL&P and another municipal customer are effective through January 31, 2020 and June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to April 30, 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.

In 2015, Minnesota Power amended its wholesale electric contracts with 14 municipal customers, extending the contract terms through December 31, 2024. No termination notices may be given prior to December 31, 2021. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will not increase by more than two percent or decrease by more than one percent from the previous year’s capacity charge and will be determined using a cost-based formula methodology. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

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 Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission cost recovery filings.

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

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

Prior to the November 2016 MPUC order, Minnesota Power accounted for North Dakota investment tax credits based on the long‑standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power had recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries were included in the ALLETE consolidated group.

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

Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a December 2016 order; however, in an order dated March 22, 2017, the MPUC approved a request by Minnesota Power to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.)

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order that allows for a 10.9 percent return on common equity. In June 2016, SWL&P filed a rate increase request with the PSCW requesting an average increase of 3.1 percent for retail customers (3.5 percent increase in electric rates; 1.3 percent decrease in natural gas rates; and 7.8 percent increase in water rates). The filing seeks an overall return on equity of 10.9 percent and a 55 percent equity ratio. On an annualized basis, the requested rate increase would generate approximately $2.7 million in additional revenue. The Company anticipates new rates will take effect in mid-2017. We cannot predict the level of rates that may be approved by the PSCW.

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 the next steps in Minnesota Power’s EnergyForward 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.

NOTE 6. REGULATORY MATTERS (Continued)

Integrated Resource Plan (Continued)

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

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 order, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Transmission Cost Recovery Rider.) 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 $56.8 million have been incurred through March 31, 2017, of which $29.6 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014.

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 expected in 2017. The final decision from the FERC is not expected to have a material impact on our Consolidated Financial Statements.

Minnesota Solar Energy Standard. In 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kW or less. Minnesota Power has two completed solar projects and another solar project is under development. In 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota. In a February 2016 order, the MPUC approved Camp Ripley as eligible to meet the solar energy standard and for current cost recovery, which was subsequently finalized by the MPUC in a December 2016 order. Camp Ripley was completed in the fourth quarter of 2016. In 2015, Minnesota Power filed for MPUC approval of 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. In a July 2016 order, the MPUC approved the community solar garden project and cost recovery, subject to certain compliance requirements. Minnesota Power believes these projects will meet approximately one-third of the overall mandate. Additionally, 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 20 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	March 31, 2017		December 31, 2016
Millions
Current Regulatory Assets
Deferred Fuel Adjustment Clause		$18.4		$18.6
Total Current Regulatory Assets	18.4		18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans	224.1		226.1
Income Taxes (a)	34.6		33.8
Asset Retirement Obligations	27.1		26.0
Cost Recovery Riders	20.1		30.5
PPACA Income Tax Deferral	5.0		5.0
Other	10.0		8.7
Total Non-Current Regulatory Assets	320.9		330.1
Total Regulatory Assets		$339.3		$348.7

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$56.8		$56.8
North Dakota Investment Tax Credits	27.4		28.2
Income Taxes	19.2		19.1
Plant Removal Obligations	18.9		19.1
Other	2.7		2.6
Total Non-Current Regulatory Liabilities		$125.0		$125.8


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

Investment in ATC

3 Months Ended

Mar. 31, 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 March 31, 2017, our equity investment in ATC was $140.2 million ($135.6 million at December 31, 2016). In the first three months of 2017, we invested $3.1 million in ATC, and on April 28, 2017, we invested an additional $1.9 million. We expect to make additional investments of approximately $5.9 million in 2017.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2016		$135.6
Cash Investments	3.1
Equity in ATC Earnings	6.1
Distributed ATC Earnings	(4.6		)
Equity Investment Balance as of March 31, 2017		$140.2

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 expected in 2017. (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

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

The following tables present ALLETE’s short-term and long-term debt as of March 31, 2017 and December 31, 2016:



March 31, 2017	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt (a)		$164.5	$(0.6)		$163.9
Long-Term Debt	1,380.2		(10.0)	1,370.2
Total Debt		$1,544.7	$(10.6)		$1,534.1


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



December 31, 2016	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt (a)		$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


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

No long-term debt was issued in the first three months of 2017.

In December 2016, ALLETE entered into an agreement to sell $80 million of the Company's senior unsecured notes (the Notes) to certain institutional buyers in the private placement market. The Notes will be sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes will be issued on or about June 1, 2017, carry an interest rate of 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. The Company 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 will be used to redeem debt, fund corporate growth opportunities and/or 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 March 31, 2017, our ratio was approximately 0.43 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of March 31, 2017, ALLETE was in compliance with its financial covenants.

Income Tax Expense

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Three Months Ended
	March 31,
	2017			2016
Millions
Current Tax Expense (a)
Federal	—			—
State		$0.1		$0.1
Total Current Tax Expense		$0.1		$0.1
Deferred Tax Expense
Federal	$7.3				$4.6
State	5.9			4.8
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Tax Expense	$13.0				$9.2
Total Income Tax Expense	$13.1				$9.3


(a)	For the three months ended March 31, 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.



	Three Months Ended
Reconciliation of Taxes from Federal Statutory	March 31,
Rate to Total Income Tax Expense	2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$62.1			$55.7
Statutory Federal Income Tax Rate	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$21.7			$19.5
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	3.9			3.2
Production Tax Credits	(13.0		)	(13.9		)
Regulatory Differences for Utility Plant	0.1			(0.1		)
Other	0.4			0.6
Total Income Tax Expense		$13.1			$9.3

For the three months ended March 31, 2017, the effective tax rate was 21.1 percent (16.7 percent for the three months ended March 31, 2016).

Uncertain Tax Positions. As of March 31, 2017, we had gross unrecognized tax benefits of $2.0 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	3 Months Ended
	Mar. 31, 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 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 three months ended March 31, 2017, and 2016, reclassifications out of accumulated other comprehensive loss for the Company were not material. Changes in accumulated other comprehensive loss for the three months ended March 31, 2017, are presented on the Consolidated Statement of Shareholders’ Equity.

Earnings Per Share and Common Stock [Text Block]

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

+ References + Details

Earnings Per Share and Common Stock

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

EARNINGS PER SHARE AND COMMON STOCK

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the three months ended March 31, 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
Three Months Ended March 31,
Net Income Attributable to ALLETE		$49.0			$49.0		$45.9			$45.9
Average Common Shares	50.2		0.2	50.4		49.2		—	49.2
Earnings Per Share		$0.97			$0.97		$0.93			$0.93

Contributions to Pension. For the three months ended March 31, 2017, we contributed 0.2 million shares of ALLETE common stock to our defined benefit pension plan, which had an aggregate value of $13.5 million when contributed (no shares were contributed to the defined benefit pension plan for the three months ended March 31, 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

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2017			2016			2017			2016
Millions
Three Months Ended March 31,
Service Cost		$2.5			$2.0			$1.1			$1.0
Interest Cost	8.1			8.1			1.9			1.9
Expected Return on Plan Assets	(10.6		)	(10.6		)	(2.6		)	(2.8		)
Amortization of Prior Service Credits	—			—			(0.5		)	(0.7		)
Amortization of Net Loss	2.5			2.4			0.1			—
Net Periodic Benefit Expense (Income)		$2.5			$1.9		—			$(0.6)

Employer Contributions. For the three months ended March 31, 2017, we contributed $1.7 million in cash and $13.5 million in ALLETE common stock to the defined benefit pension plan (none for the three months ended March 31, 2016); we do not expect to make additional contributions to our defined benefit pension plan in 2017. For the three months ended March 31, 2017, and 2016, we made no contributions to our other postretirement benefit plan; we do not expect to make any contributions to our other postretirement benefit plan in 2017.

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 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 March 31, 2017, Square Butte had total debt outstanding of $313.7 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 three months ended March 31, 2017, was $20.3 million ($18.5 million for the three months ended March 31, 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 $2.3 million ($2.4 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.

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 2017 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 2019. The minimum annual payment obligation under these supply and transportation agreements is $20.7 million for the remainder of 2017, $27.0 million in 2018, $1.8 million in 2019 and none thereafter. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Energy is obligated to make lease payments for a dragline totaling $2.8 million annually 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 $10.3 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

In 2015, a certificate of need was approved by the MPUC. Based on this order, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Note 6. Regulatory Matters.) 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 $56.8 million have been incurred through March 31, 2017, of which $29.6 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 to conduct such operations have been obtained. We anticipate that with many state and federal environmental regulations finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 the latest step in its EnergyForward strategic plan. We believe that costs to retire 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 a total of 28 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 that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold.

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.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs and work practice standards for the remaining categories. Affected sources were required to be in compliance with the rule by April 2015. States had the authority to grant sources a one-year extension. The MPCA approved Minnesota Power’s request for an extension of the date of compliance for the Boswell Unit 4 environmental upgrade to April 2016. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed in 2015. Boswell Unit 3 is also subject to the MATS rule; however, investments and compliance work completed at Boswell Unit 3, including 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, even after considering cost of compliance. The outcome of these proceedings is not expected to have a material impact on Minnesota Power generation due to emission reduction obligations under the Minnesota Mercury Emissions Reduction Act and the Consent Decree. (See New Source Review.)

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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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.

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 United States District Court for the Northern District of California alleging the EPA had failed to fully implement the PM_2.5standards in 24 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. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by 2013; however, the State of Minnesota delayed completing the documents pending EPA guidance to states for preparing the SIP submittal.

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. The SIP stated that since the EPA determined in 2012 that no area in the country is in violation of the one-hour NO₂ NAAQS, there are no nonattainment areas in the country for this pollutant, and therefore Minnesota’s NO₂ emissions cannot be significantly contributing to nonattainment in any other state. In 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. As such, additional compliance costs for the one-hour NO₂ NAAQS are not expected at this time.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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. The MPCA was required to notify the EPA as to how each source will evaluate air quality by July 2016. 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. 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. Five other reservations across the U.S. have received Class I status. A public hearing was held by the Fond du Lac Band and the public comment period on the petition expired in 2014. After the Fond du Lac Band prepares responses to the comments, it is anticipated to make a formal submittal request to the EPA.

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 and was followed by public hearings and public comment period ending in 2015. After the Bad River Band prepares responses to the comments, it is also anticipated to make a formal submittal request to the EPA.

There is no deadline for the approval, denial, or modification of these requests by the EPA. We are unable to determine the impact of potential Class I status on the Company’s operations at this time.

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:


•	Expanding our renewable energy supply;


•	Providing energy conservation initiatives for our customers and engaging in other demand side efforts;


•	Improving efficiency of our energy generating facilities;


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


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

Climate Action Plan. In 2015, the Federal government announced an updated Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions. On March 28, 2017, President Trump signed an Executive Order titled Promoting Energy Independence and Economic Growth that rescinds the Climate Action Plan.

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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 power to require BACT for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions. At this time, we are unable to predict the compliance costs that we might incur.

In 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 as to how the Title V permitting requirements will be affected by the March 28, 2017, Executive Order titled Promoting Energy Independence and Economic Growth.

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. Minnesota Power is monitoring developments with respect to the CPP rule 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In developing its plan, a state may choose to meet either the mass-based or the rate-based goals. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota as well as its potential impact on the Company and is actively discussing potential compliance scenarios with regulatory agencies and in public stakeholder meetings. Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 6. Regulatory Matters.)

We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. Minnesota Power would seek recovery of any additional costs through 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 5 years. Minnesota Power would seek recovery of any additional costs through a general rate case.

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. The ELG rule also prohibits the discharge of bottom and fly ash contact waters. Compliance with the final rule is required between November 1, 2018, and December 31, 2023.

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

On April 12, 2017, the EPA announced that it would reconsider the final ELG rule and administratively stay the compliance dates set forth in the rule. The EPA has received seven petitions for review of the ELG rule, which were consolidated in the U.S. Court of Appeals for the Fifth Circuit in late 2015. The EPA has indicated they will also file a motion requesting that court to hold litigation challenging the ELG rule in abeyance while the EPA reconsiders the rule. All pending deadlines under the ELG rule will be stayed while the EPA re-examines it. 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

At this time, we cannot estimate what compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. Minnesota Power would seek recovery of any additional costs through 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 disposes or stores 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 or trucking ash to state permitted landfills.

The EPA issued the final 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 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. Compliance costs, if any for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of any additional costs through a general rate case.

Other Environmental Matters. In November 2016, U.S. Water Services received notice from the EPA regarding potential violations under the Federal Insecticide, Fungicide and Rodenticide Act for the sale of certain chemicals without registration or that were misbranded. The potential violations primarily related to sales in 2013 by a U.S. Water Services subsidiary which occurred prior to U.S. Water Services’ acquisition of that subsidiary. In the first quarter of 2017, U.S. Water Services reached a settlement with the EPA and entered into a consent agreement which provides for the payment of approximately $0.2 million to resolve this matter.

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 March 31, 2017, ALLETE Clean Energy has $14.6 million outstanding in standby letters of credit.

U.S. Water Services. As of March 31, 2017, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of March 31, 2017, BNI Energy had surety bonds outstanding of $49.9 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Energy has secured a letter of credit for an additional $0.6 million to provide for BNI Energy’s total reclamation liability, which is currently estimated at $47.5 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of March 31, 2017, ALLETE Properties, through its subsidiaries, 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 $5.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Community Development District Obligations. At March 31, 2017, we owned 71 percent of the assessable land in the Town Center District (72 percent at December 31, 2016) and 89 percent of the assessable land in the Palm Coast Park District (92 percent at December 31, 2016). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are approximately $1.4 million for Town Center at Palm Coast and $2.1 million for Palm Coast Park. As we sell property at these projects, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

Business Segments

3 Months Ended

Mar. 31, 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.



	Three Months Ended
	March 31,
	2017			2016
Millions
Operating Revenue
Regulated Operations	$281.6			$252.3

Energy Infrastructure and Related Services
ALLETE Clean Energy	23.7			23.6
U.S. Water Services	32.1			32.4

Corporate and Other	28.2			25.5
Total Operating Revenue		$365.6			$333.8
Net Income (Loss) Attributable to ALLETE
Regulated Operations		$43.5			$42.4

Energy Infrastructure and Related Services
ALLETE Clean Energy	6.7			6.1
U.S. Water Services	(0.3		)	(0.5		)

Corporate and Other	(0.9		)	(2.1		)
Total Net Income Attributable to ALLETE		$49.0			$45.9

NOTE 14. BUSINESS SEGMENTS (Continued)



	March 31, 2017		December 31, 2016
Millions
Assets
Regulated Operations	$3,828.2		$3,823.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	571.7		566.0
U.S. Water Services	265.1		264.1

Corporate and Other	276.9		222.9
Total Assets		$4,941.9		$4,876.9

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

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-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Operations and Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 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. Fuel for generation is carried at an average cost basis. Certain other inventories, including capital spares, are carried at specific cost.
Subsequent Events [Policy Text Block]	The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.
New Accounting Standards [Policy Text Block]	Simplifying the Measurement of Inventory. In 2015, the FASB issued an accounting standard which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance 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. 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 new guidance, 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 expense to be eligible for capitalization. The other components of net periodic expense will be presented separately from the line item that includes the service cost and will be excluded from the operating income subtotal. This accounting guidance is effective for the Company beginning in the first quarter of 2018. The adoption of this guidance by the Company is expected to result in higher operating expense and lower operating income. This guidance is not expected to have an impact on net income. We will continue to evaluate the impact of this standard on our Consolidated Financial Statements. Revenue from Contracts with Customers. In 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. The Company is considering the impact of the new guidance on its ability to recognize revenue from certain contracts where collectibility is in question and bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). The guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company will adopt this guidance for our fiscal year beginning January 1, 2018. 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 amended lease guidance on our Consolidated Financial Statements. Financial Instruments. In January 2016, the FASB issued an accounting standard update which requires entities to measure their investments at fair value and recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The updated guidance is effective for the Company beginning in the first quarter of 2018. We are currently evaluating the impact that the standard will have on our Consolidated Financial Statements. NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued) New Accounting Pronouncements (Continued) 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. The guidance will result in changes to the Company’s Consolidated Statement of Cash Flows relating to debt prepayments, contingent consideration payments, proceeds from insurance settlements, proceeds from corporate-owned life insurance policies and distributions received from equity method investees. 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. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018, and 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.
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 three months ended March 31, 2017, and 2016.
Available-for-sale Investments [Policy Text Block]	We account for our available-for-sale 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 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. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.
North Dakota Investment Tax Credits [Policy Text Block]	Prior to the November 2016 MPUC order, Minnesota Power accounted for North Dakota investment tax credits based on the long‑standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power had recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries were included in the ALLETE consolidated group.
Regulatory Assets and Liabilities [Policy Text Block]	Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.
Equity Method Investments [Policy Text Block]	We account for our investment in ATC under the equity method of accounting.
Income Tax [Policy Text Block]	The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate, and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.
Earnings Per Share [Policy Text Block]	We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the three months ended March 31, 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)

3 Months Ended

Mar. 31, 2017

Inventories [Table Text Block]



Inventories – Net	March 31, 2017			December 31, 2016
Millions
Fuel (a)		$48.3			$43.9
Materials and Supplies	49.0			48.7
Raw Materials	2.9			2.9
Work in Progress	1.4			1.0
Finished Goods	9.9			8.6
Reserve for Obsolescence	(1.0		)	(0.9		)
Total Inventories – Net		$110.5			$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	March 31, 2017		December 31, 2016
Millions
Deferred Fuel Adjustment Clause		$18.4		$18.6
Restricted Cash	9.1		2.2
Other	18.0		19.5
Total Prepayments and Other Current Assets		$45.5		$40.3

Other Non-Current Assets [Table Text Block]



Other Non-Current Assets	March 31, 2017		December 31, 2016
Millions
Contract Payment		$28.9		$29.6
Finance Receivable	11.5		11.5
Restricted Cash	8.6		8.6
Other	56.2		56.8
Total Other Non-Current Assets		$105.2		$106.5

Other Current Liabilities [Table Text Block]



Other Current Liabilities	March 31, 2017		December 31, 2016
Millions
PSAs		$24.6		$24.6
Contingent Consideration (a)	4.6		—
Other	41.4		49.1
Total Other Current Liabilities		$70.6		$73.7


(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.)

Other Non-Current Liabilities [Table Text Block]



Other Non-Current Liabilities	March 31, 2017		December 31, 2016
Millions
Asset Retirement Obligation		$157.2		$136.6
PSAs	107.6		113.8
Contingent Consideration (a)	5.4		25.0
Other	46.7		47.3
Total Other Non-Current Liabilities		$316.9		$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.



Three Months Ended March 31,	2017		2016
Millions
Cash Paid During the Period for Interest – Net of Amounts Capitalized		$18.9		$19.6
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(3.5)		$(25.6)
Capitalized Asset Retirement Costs		$19.3		$3.5
AFUDC–Equity		$0.2		$0.9
ALLETE Common Stock Contributed to the Pension Plan		$13.5	—

Acquisitions (Table)

3 Months Ended

Mar. 31, 2017

Water & Energy Systems Technology [Member]

Business Acquisition [Line Items]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Cash and Cash Equivalents		$0.1
Other Current Assets	1.1
Customer Relationships (a)	2.8
Goodwill (a)(b)	3.9
Other Non-Current Assets	0.1
Total Assets Acquired		$8.0
Liabilities Assumed
Current Liabilities		$0.2
Non-Current Liabilities	1.2
Total Liabilities Assumed		$1.4
Net Identifiable Assets Acquired		$6.6


(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.

Fair Value (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

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	0.5
Payments (a)	(15.1		)
Changes in Cash Flow Projections (b)	(0.4		)
Balance as of March 31, 2017		$10.0


(a)	Payments relate to retirement of U.S. Water Services former employees.

(b)

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of March 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$7.5	—		—			$7.5
Available-for-sale – Corporate and Governmental Debt Securities	—			$12.1	—		12.1
Cash Equivalents	2.6		—		—		2.6
Total Fair Value of Assets		$10.1		$12.1	—			$22.2

Liabilities (b)
Deferred Compensation	—			$17.2	—			$17.2
U.S. Water Services Contingent Consideration	—		—			$10.0	10.0
Total Fair Value of Liabilities	—			$17.2		$10.0		$27.2
Total Net Fair Value of Assets (Liabilities)		$10.1	$(5.1)		$(10.0)		$(5.0)


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


(b)	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet with the exception of the current portion of the U.S. Water Services Contingent Consideration which is included in Other Current Liabilities. (See Note 1. Operations and Significant Accounting Policies.)



	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.

Financial Instruments [Table Text Block]



Financial Instruments	Carrying Amount	Fair Value
Millions
Long-Term Debt, Including Long-Term Debt Due Within One Year
March 31, 2017	$1,543.4	$1,614.9
December 31, 2016	$1,569.1	$1,653.8

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	March 31, 2017		December 31, 2016
Millions
Current Regulatory Assets
Deferred Fuel Adjustment Clause		$18.4		$18.6
Total Current Regulatory Assets	18.4		18.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans	224.1		226.1
Income Taxes (a)	34.6		33.8
Asset Retirement Obligations	27.1		26.0
Cost Recovery Riders	20.1		30.5
PPACA Income Tax Deferral	5.0		5.0
Other	10.0		8.7
Total Non-Current Regulatory Assets	320.9		330.1
Total Regulatory Assets		$339.3		$348.7

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$56.8		$56.8
North Dakota Investment Tax Credits	27.4		28.2
Income Taxes	19.2		19.1
Plant Removal Obligations	18.9		19.1
Other	2.7		2.6
Total Non-Current Regulatory Liabilities		$125.0		$125.8


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

Income Tax Expense (Tables)

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



	Three Months Ended
	March 31,
	2017			2016
Millions
Current Tax Expense (a)
Federal	—			—
State		$0.1		$0.1
Total Current Tax Expense		$0.1		$0.1
Deferred Tax Expense
Federal	$7.3				$4.6
State	5.9			4.8
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Tax Expense	$13.0				$9.2
Total Income Tax Expense	$13.1				$9.3


(a)	For the three months ended March 31, 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]



	Three Months Ended
Reconciliation of Taxes from Federal Statutory	March 31,
Rate to Total Income Tax Expense	2017			2016
Millions
Income Before Non-Controlling Interest and Income Taxes		$62.1			$55.7
Statutory Federal Income Tax Rate	35		%	35		%
Income Taxes Computed at 35 percent Statutory Federal Rate		$21.7			$19.5
Increase (Decrease) in Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	3.9			3.2
Production Tax Credits	(13.0		)	(13.9		)
Regulatory Differences for Utility Plant	0.1			(0.1		)
Other	0.4			0.6
Total Income Tax Expense		$13.1			$9.3

Pension and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

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



	Pension						Other Postretirement
Components of Net Periodic Benefit Expense (Income)	2017			2016			2017			2016
Millions
Three Months Ended March 31,
Service Cost		$2.5			$2.0			$1.1			$1.0
Interest Cost	8.1			8.1			1.9			1.9
Expected Return on Plan Assets	(10.6		)	(10.6		)	(2.6		)	(2.8		)
Amortization of Prior Service Credits	—			—			(0.5		)	(0.7		)
Amortization of Net Loss	2.5			2.4			0.1			—
Net Periodic Benefit Expense (Income)		$2.5			$1.9		—			$(0.6)

Business Segments (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Business Segments [Table Text Block]



	Three Months Ended
	March 31,
	2017			2016
Millions
Operating Revenue
Regulated Operations	$281.6			$252.3

Energy Infrastructure and Related Services
ALLETE Clean Energy	23.7			23.6
U.S. Water Services	32.1			32.4

Corporate and Other	28.2			25.5
Total Operating Revenue		$365.6			$333.8
Net Income (Loss) Attributable to ALLETE
Regulated Operations		$43.5			$42.4

Energy Infrastructure and Related Services
ALLETE Clean Energy	6.7			6.1
U.S. Water Services	(0.3		)	(0.5		)

Corporate and Other	(0.9		)	(2.1		)
Total Net Income Attributable to ALLETE		$49.0			$45.9

NOTE 14. BUSINESS SEGMENTS (Continued)



	March 31, 2017		December 31, 2016
Millions
Assets
Regulated Operations	$3,828.2		$3,823.9

Energy Infrastructure and Related Services
ALLETE Clean Energy	571.7		566.0
U.S. Water Services	265.1		264.1

Corporate and Other	276.9		222.9
Total Assets		$4,941.9		$4,876.9

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

Mar. 31, 2017

Dec. 31, 2016

Inventories – Net [Abstract]

Fuel

^[1]

$ 48.3

$ 43.9

Materials and Supplies

49.0

48.7

Raw Materials

2.9

Work in Progress

1.4

1.0

Finished Goods

9.9

8.6

Reserve for Obsolescence

(1.0)

(0.9)

Total Inventories – Net

110.5

104.2

Prepayments and Other Current Assets [Abstract]

Deferred Fuel Adjustment Clause

18.4

18.6

Restricted Cash

9.1

2.2

Total Prepayments and Other Current Assets

18.0

19.5

45.5

40.3

Other Non-Current Assets [Abstract]

Contract Payment

28.9

29.6

Finance Receivable

11.5

Restricted Cash

8.6

Total Other Non-Current Assets

56.2

56.8

105.2

106.5

Other Current Liabilites [Abstract]

PSAs

24.6

Contingent Consideration

^[2]

4.6

0.0

Total Other Current Liabilities

41.4

49.1

70.6

73.7

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

157.2

136.6

PSAs

107.6

113.8

Contingent Consideration

^[3]

5.4

25.0

Total Other Non-Current Liabilities

46.7

47.3

$ 316.9

$ 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.)
[3]	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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash Paid During the Period for Interest – Net of Amounts Capitalized	$ 18.9	$ 19.6
Noncash Investing and Financing Activities [Abstract]
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	3.5	25.6
Capitalized Asset Retirement Costs	19.3	3.5
AFUDC–Equity	0.2	0.9
ALLETE Common Stock Contributed to the Pension Plan	$ 13.5	$ 0.0

Operations and Significant Accounting Policies - New Accounting Standards (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Accounting Standards Update 2016-09 [Member] \| Income Tax Expense (Benefit) [Member] \| Maximum [Member]
New Accounting Standards [Line Items]
Effect of the Adoption	$ 1.0

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

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

3 Months Ended

Mar. 31, 2017

Mar. 31, 2016

Dec. 31, 2016

Available-for-sale Securities

ALLETE Properties

$ 31.6

$ 31.7

19.6

^[1]

18.8

2.6

1.3

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

3.9

3.8

Total Other Investments

57.7

$ 55.6

One Year or Less

0.2

One Year to Less Than Three Years

3.0

Three Years to Less Than Five Years

5.0

Five or More Years

3.9

Impairment of Land Inventory

$ 0.0

[1]

As of March 31, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $3.0 million, in three years to less than five years was $5.0 million and in five or more years was $3.9 million.

Acquisitions - Acquisition of Non-Controlling Interest (Details) - ALLETE Clean Energy [Member] $ in Millions	1 Months Ended
	Apr. 30, 2016 USD ($)
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

Oct. 31, 2016

Mar. 31, 2017

Dec. 31, 2016

Assets Acquired [Abstract]

Goodwill

$ 131.2

Water & Energy Systems Technology [Member]

Business Acquisition [Line Items]

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Water & Energy Systems Technology of Nevada, Inc.

Total Consideration

$ 6.5

Cash Payment to Acquire Business

5.9

Payment Due in April 2018

0.6

Assets Acquired [Abstract]

Cash and Cash Equivalents

0.1

Other Current Assets

1.1

Customer Relationships

^[1]

2.8

Goodwill

^[1],[2]

3.9

Other Non-Current Assets

0.1

Total Assets Acquired

8.0

Liabilities Assumed [Abstract]

Current Liabilities

0.2

Non-Current Liabilities

1.2

Total Liabilities Assumed

1.4

Net Identifiable Assets Acquired

6.6

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 - Goodwill (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 131.2	$ 131.2
Changes to Goodwill	$ 0.0

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

3 Months Ended

Mar. 31, 2017

Mar. 31, 2016

Dec. 31, 2016

Definite-Lived Intangible Assets [Roll Forward]

$ 65.6

Amortization

(1.4)

$ (1.3)

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

64.2

Accumulated Amortization

10.7

$ 9.3

4.1

5.1

4.8

4.5

4.4

41.3

Intangible Assets [Abstract]

Total Intangible Assets

80.8

$ 82.2

Total Intangible Assets, Amortization

$ (1.4)

$ (1.3)

Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Trademarks and Trade Names [Member]

20 years

Indefinite-Lived Intangible Assets [Roll Forward]

$ 16.6

Customer Relationships [Member]

16.6

Definite-Lived Intangible Assets [Roll Forward]

59.3

Amortization

(1.1)

$ 58.2

Total Intangible Assets, Amortization

21 years

Intangible Assets [Abstract]

$ (1.1)

Developed Technology and Other [Member]

Definite-Lived Intangible Assets [Roll Forward]

^[1]

6.3

Amortization

^[1]

(0.3)

Total Intangible Assets, Amortization

^[1]

6.0

Intangible Assets [Abstract]

^[1]

$ (0.3)

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

Definite-Lived Intangible Assets [Roll Forward]

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

2 years

Definite-Lived Intangible Assets [Roll Forward]

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

12 years

Definite-Lived Intangible Assets [Roll Forward]

8 years

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

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

3 Months Ended

12 Months Ended

Mar. 31, 2017

Dec. 31, 2016

$ 2.6

$ 1.3

U.S. Water Services Contingent Consideration, Current

^[1]

4.6

0.0

Recurring Fair Value Measurements [Member]

Available-for-sale – Corporate and Governmental Debt Securities

7.5

^[2]

7.1

^[3]

12.1

^[2]

11.7

^[3]

2.6

^[2]

1.3

^[3]

22.2

20.1

17.2

^[4]

16.0

^[5]

10.0

^[4]

25.0

^[5]

27.2

41.0

Fair Value Hierarchy Transfers, All Levels

(5.0)

(20.9)

0.0

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

Available-for-sale – Corporate and Governmental Debt Securities

7.5

^[2]

7.1

^[3]

0.0

^[2]

0.0

^[3]

2.6

^[2]

1.3

^[3]

10.1

8.4

0.0

^[4]

0.0

^[5]

0.0

^[4]

0.0

^[5]

0.0

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

10.1

8.4

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[2]

0.0

^[3]

12.1

^[2]

11.7

^[3]

0.0

^[2]

0.0

^[3]

12.1

11.7

17.2

^[4]

16.0

^[5]

0.0

^[4]

0.0

^[5]

17.2

16.0

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

(5.1)

(4.3)

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[2]

0.0

^[3]

0.0

^[2]

0.0

^[3]

0.0

^[2]

0.0

^[3]

0.0

0.0

^[4]

0.0

^[5]

10.0

^[4]

25.0

^[5]

10.0

25.0

(10.0)

(25.0)

25.0

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

10.0

$ 25.0

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

Activity in Level 3

0.5

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

Activity in Level 3

^[6]

(15.1)

Activity in Level 3

^[7]

$ (0.4)

[1]	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.)
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Investments on the Consolidated Balance Sheet.
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet with the exception of the current portion of the U.S. Water Services Contingent Consideration which is included in Other Current Liabilities. (See Note 1. Operations and Significant Accounting Policies.)
[5]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[6]	Payments relate to retirement of U.S. Water Services former employees.
[7]	Changes in cash flow projections reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, which were paid in April 2017, resulting in $4.6 million of the U.S. Water Services Contingent Consideration liability being classified in Other Current Liabilities on the Consolidated Balance Sheet. The remaining liability will be paid through the first quarter of 2019.

Fair Value - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,543.4	$ 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	$ 1,614.9	$ 1,653.8

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

Regulatory Matters - Electric Rates (Details) $ in Millions					3 Months Ended		8 Months Ended	12 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Feb. 28, 2017 USD ($)	Dec. 12, 2016 USD ($)	Nov. 02, 2016 USD ($)	Jun. 28, 2016 USD ($)	Mar. 31, 2017 USD ($) Customers Years MW	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
PSCW [Member] \| 2012 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity					10.90%
PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)				3.10%
Requested Return on Equity				10.90%
Requested Equity Ratio				55.00%
Annual Additional Revenue Generated from Requested Final Rate Increase				$ 2.7
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					$ 24.2	$ 25.4
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)			9.00%
Requested Return on Equity			10.25%
Requested Equity Ratio			53.80%
Annual Additional Revenue Generated from Requested Final Rate Increase	$ 39.0		$ 55.0
Annual Additional Revenue Generated from Requested Interim Rate Increase		$ 34.7	49.0		$ 34.7
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] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Subsequent Event [Member]
Regulatory Matters [Line Items]
Annual Additional Revenue Generated from Requested Interim Rate Increase							$ 32.2
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Retail Customers [Member] \| Corporate and Other [Member]
Regulatory Matters [Line Items]
After-Tax Charge for North Dakota Investment Tax Credits Reversed								$ 8.8
Electric Rates [Member] \| MPUC [Member] \| Renewable Cost Recovery Rider [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Reduction in Operating Revenue due to Regulatory Outcome								$ 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
Notice Required to Terminate (Years) \| Years					3
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire December 2024) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers					14
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire December 2024) [Member] \| Maximum [Member]
Regulatory Matters [Line Items]
Change in Annual Capacity Charge Per Contract, Percentage					2.00%
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire December 2024) [Member] \| Minimum [Member]
Regulatory Matters [Line Items]
Change in Annual Capacity Charge Per Contract, Percentage					(1.00%)
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contract (Termination Effective June 2019) [Member]
Regulatory Matters [Line Items]
Average Monthly Demand (MW) \| MW					29
Electric Rates [Member] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contract (Cost-Based Formula Methodology for Entire Term) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers					3
Electric Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)				3.50%
Natural Gas Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)				(1.30%)
Water Rates [Member] \| PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Rate Increase (Decrease)				7.80%

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - Integrated Resource Plan [Member] - Natural Gas-Fired [Member] - Minnesota Power [Member]	Mar. 31, 2017 MW
Minimum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	200
Maximum [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	300

Regulatory Matters - Great Northern Transmission Line (Details) - Great Northern Transmission Line [Member] $ in Millions	Mar. 31, 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	$ 56.8
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	$ 29.6
MPUC [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Transmission Line Length (Miles) \| Miles	220
Transmission Line Capacity (kV) \| kV	500

Regulatory Matters - MISO Return on Equity Complaints (Details) - FERC [Member]	Mar. 31, 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]	Mar. 31, 2017 Projects MW
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Overall Mandate Percentage	1.50%
Minimum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Small Scale Solar Mandate Percentage	10.00%
Maximum [Member]
Regulatory Matters [Line Items]
Solar Energy Standard Mandate - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.02
Minnesota Solar Energy Standard [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Number of Projects \| Projects	2
Solar Energy Standard Mandate - Percentage of Overall Mandate Expected to be Met with Current Filings or Projects	33.00%
Minnesota Solar Energy Standard - Camp Ripley Project [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	10
Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	1
Minnesota Solar Energy Standard - Community Solar Garden Project - Owned and Operated [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity (MW)	0.04

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

3 Months Ended

Mar. 31, 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

$ 18.4

$ 18.6

320.9

330.1

Total Regulatory Assets

339.3

348.7

Wholesale and Retail Contra AFUDC [Member]

125.0

125.8

North Dakota Investment Tax Credits [Member]

56.8

27.4

28.2

Income Taxes [Member]

Plant Removal Obligations [Member]

19.2

19.1

Deferred Fuel Adjustment Clause [Member]

18.9

19.1

Current Regulatory Assets

18.4

18.6

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

224.1

226.1

Income Taxes [Member]

Asset Retirement Obligations [Member]

^[1]

34.6

33.8

Cost Recovery Riders [Member]

27.1

26.0

PPACA Income Tax Deferral [Member]

20.1

30.5

5.0

10.0

8.7

Short-Term Debt - Principal

$ 2.7

$ 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
Investment in ATC (Details) $ in Millions	Apr. 28, 2017 USD ($)	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Sep. 27, 2016
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2016		$ 135.6
Cash Investments		3.1	$ 1.2
Equity in ATC Earnings		6.1	$ 4.8
Equity Investment Balance as of March 31, 2017		$ 140.2
FERC [Member] \| Return on Equity Complaint 2 [Member]
ALLETE's Investment in ATC [Roll Forward]
Proposed Return on Equity		9.70%
Proposed Return on Equity, Including Incentive Adder		10.20%
ATC [Member]
Investment in ATC [Line Items]
Ownership Percentage		8.00%
Expected Additional Investment in 2017		$ 5.9
ALLETE's Investment in ATC [Roll Forward]
Equity Investment Balance as of December 31, 2016		135.6
Cash Investments		3.1
Equity in ATC Earnings		6.1
Distributed ATC Earnings		(4.6)
Equity Investment Balance as of March 31, 2017		$ 140.2
Authorized Return on Equity		10.32%		12.20%
Authorized Return on Equity, Including Incentive Adder		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
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	$ 1.9

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

3 Months Ended

Mar. 31, 2017

Dec. 31, 2016

Debt Instrument [Line Items]

$ 164.5

^[1]

$ 188.3

^[2]

Short-Term Debt - Unamortized Debt Issuance Costs

(0.6)

^[1]

(0.6)

^[2]

Short-Term Debt - Total

163.9

^[1]

187.7

^[2]

Long-term Debt - Principal

1,380.2

1,380.8

Long-Term Debt - Unamortized Debt Issuance Costs

(10.0)

(10.4)

Long-Term Debt - Total

1,370.2

1,370.4

Total Debt - Principal

1,544.7

1,569.1

Total Debt - Unamortized Debt Issuance Costs

(10.6)

(11.0)

Total Debt - Total

1,534.1

$ 1,558.1

Long-Term Debt Issued

0.0

ALLETE Senior Unsecured Notes 3.11% Due 2027 [Member]

Debt Instrument [Line Items]

Expected Proceeds from Future Issuance of Senior Unsecured Notes

$ 80.0

Expected Future Interest Rate

3.11%

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

Short-Term and Long-Term Debt - Financial Covenants (Details)	Mar. 31, 2017
Debt Instrument [Line Items]
Actual Ratio of Indebtedness to Total Capitalization	0.43
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

Mar. 31, 2017

Mar. 31, 2016

Dec. 31, 2016

Current Tax Expense [Abstract]

Federal

^[1]

$ 0.0

State

^[1]

0.1

Total Current Tax Expense

0.1

Deferred Tax Expense [Abstract]

Federal

7.3

4.6

State

5.9

4.8

Investment Tax Credit Amortization

(0.2)

Total Deferred Tax Expense

13.0

9.2

Total Income Tax Expense

13.1

9.3

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

Income Before Non-Controlling Interest and Income Taxes

$ 62.1

$ 55.7

Statutory Federal Income Tax Rate

35.00%

Income Taxes Computed at 35 percent Statutory Federal Rate

$ 21.7

$ 19.5

Increase (Decrease) in Tax [Abstract]

State Income Taxes – Net of Federal Income Tax Benefit

3.9

3.2

Production Tax Credits

(13.0)

(13.9)

Regulatory Differences for Utility Plant

0.1

(0.1)