Acquisitions [Text Block]

Investments [Text Block]

INVESTMENTS

Investments. As of March 31, 2018, 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, 2018		December 31, 2017
Millions
ALLETE Properties		$26.0		$26.4
Available-for-sale Securities (a)	21.1		19.1
Cash Equivalents	2.0		3.8
Other	3.7		3.8
Total Other Investments		$52.8		$53.1


(a)	As of March 31, 2018, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.9 million, in one year to less than three years was $3.4 million, in three years to less than five years was $3.3 million and in five or more years was $1.1 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, 2018, and 2017.

Available-for-Sale Securities. We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits. Gross realized and unrealized gains and losses on our available-for-sale securities were immaterial for the three months ended March 31, 2018, and 2017.

Acquisitions

3 Months Ended

Mar. 31, 2018

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, 2018, and 2017.

2017 Activity.

Tonka Water. In September 2017, U.S. Water Services acquired 100 percent of Tonka Water. Total consideration for the transaction was $19.2 million, including a working capital adjustment. Consideration of $19.0 million was paid in cash on the acquisition date and a working capital adjustment of $0.2 million was paid in the fourth quarter of 2017. Tonka Water is a supplier of municipal and industrial water treatment systems and will expand U.S. Water Services’ geographic and customer markets.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2018, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.



Millions
Assets Acquired
Accounts Receivable		$5.1
Other Current Assets	5.1
Trade Names (a)	0.9
Goodwill (a)(b)	16.9
Other Non-Current Assets	0.2
Total Assets Acquired		$28.2
Liabilities Assumed
Current Liabilities		$9.0
Total Liabilities Assumed		$9.0
Net Identifiable Assets Acquired		$19.2

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


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

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

Goodwill and Intangible Assets

3 Months Ended

Mar. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets [Text Block]

GOODWILL AND INTANGIBLE ASSETS

The aggregate carrying amount of goodwill was $148.3 million as of March 31, 2018, and December 31, 2017. There have been no changes to goodwill by reportable segment for the three months ended March 31, 2018.

Balances of intangible assets, net, excluding goodwill as of March 31, 2018, are as follows:



	December 31, 2017		Amortization	March 31, 2018
Millions
Intangible Assets
Definite-Lived Intangible Assets
Customer Relationships		$54.7	$(1.1)		$53.6
Developed Technology and Other (a)	6.3		(0.3)	6.0
Total Definite-Lived Intangible Assets	61.0		(1.4)	59.6
Indefinite-Lived Intangible Assets
Trademarks and Trade Names	16.6		n/a	16.6
Total Intangible Assets		$77.6	$(1.4)		$76.2


(a)	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

Customer relationships have a remaining useful life of approximately 20 years, and developed technology and other have remaining useful lives ranging from approximately 1 year to approximately 11 years (weighted average of approximately 7 years). The weighted average remaining useful life of all definite-lived intangible assets as of March 31, 2018, is approximately 18 years.

Amortization expense for intangible assets was $1.4 million for the three months ended March 31, 2018, and 2017. Accumulated amortization was $16.2 million as of March 31, 2018 ($14.8 million as of December 31, 2017). The estimated amortization expense for definite-lived intangible assets for the remainder of 2018 is $4.0 million. Estimated annual amortization expense for definite‑lived intangible assets is $4.9 million in 2019, $4.7 million in 2020, $4.6 million in 2021, $4.3 million in 2022 and $37.1 million thereafter.

- Definition

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

+ References + Details

Fair Value

3 Months Ended

Mar. 31, 2018

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 2017 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, 2018, and December 31, 2017. 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, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$12.4	—		—			$12.4
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.7	—		8.7
Cash Equivalents	2.0		—		—		2.0
Total Fair Value of Assets		$14.4		$8.7	—			$23.1

Liabilities
Deferred Compensation (b)	—			$20.2	—			$20.2
U.S. Water Services Contingent Consideration (c)	—		—			$5.5	5.5
Total Fair Value of Liabilities	—			$20.2		$5.5		$25.7
Total Net Fair Value of Assets (Liabilities)		$14.4	$(11.5)		$(5.5)		$(2.6)


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


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


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



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$10.2	—		—			$10.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.9	—		8.9
Cash Equivalents	3.8		—		—		3.8
Total Fair Value of Assets		$14.0		$8.9	—			$22.9

Liabilities (b)
Deferred Compensation	—			$18.2	—			$18.2
U.S. Water Services Contingent Consideration	—		—			$5.4	5.4
Total Fair Value of Liabilities	—			$18.2		$5.4		$23.6
Total Net Fair Value of Assets (Liabilities)		$14.0	$(9.3)		$(5.4)		$(0.7)


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


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

The Level 3 liability in the preceding tables is the result of the 2015 acquisition of U.S. Water Services. Changes in the U.S. Water Services Contingent Consideration can result from modifications to the shareholder agreement, changes in discount rates, timing of milestones that trigger payment, or the timing and amount of earnings estimates. The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of March 31, 2018. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2017		$5.4
Accretion	0.1
Balance as of March 31, 2018		$5.5

NOTE 5. FAIR VALUE (Continued)

For the three months ended March 31, 2018, and the year ended December 31, 2017, 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, 2018	$1,512.2	$1,583.1
December 31, 2017	$1,513.3	$1,627.6

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, 2018, and the year ended December 31, 2017, there were no triggering events or indicators of impairment for these non-financial assets.

- Definition

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

+ References + Details

Regulatory Matters

3 Months Ended

Mar. 31, 2018

Regulated Operations [Abstract]

Regulatory Matters [Text Block]

REGULATORY MATTERS

Regulatory matters are summarized in Note 4. Regulatory Matters to our Consolidated Financial Statements in our 2017 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, PSCW or FERC. 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 $24.1 million for the three months ended March 31, 2018 ($24.2 million for the three months ended March 31, 2017).

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

In February 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an April 2017 order, 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 in May 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately $49 million on an annualized basis. In an order dated March 12, 2018, the MPUC affirmed determinations made at a hearing on January 18, 2018, regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Upon commencement of final rates, we expect additional revenue of approximately $13 million on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which will be partially offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund of approximately $41 million as of March 31, 2018 ($32 million as of December 31, 2017). The MPUC also disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in the fourth quarter of 2017.

As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million pre-tax on an annual basis.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

On April 2, 2018, Minnesota Power filed a petition for reconsideration with the MPUC requesting reconsideration of certain decisions in the MPUC’s order dated March 12, 2018, collectively representing approximately $20 million to $25 million in additional revenue on an annualized basis. Minnesota Power’s petition included requesting reconsideration of the allowed return on common equity, recovery of the prepaid pension asset in rate base, certain disallowed expenses, and certain transmission revenue adjustments. On April 12, 2018, Minnesota Power responded to a Minnesota Department of Commerce (DOC) request for reconsideration requesting that the MPUC generally accept, with modifications and conditions, the DOC’s proposal to reduce the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 and use the benefits of the TCJA to offset the resulting increase in customer rates. We expect a decision on reconsideration by mid-year in 2018. We are unable to predict the outcome of this regulatory proceeding.

Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 which established a Minnesota energy policy 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. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an April 2017 order; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued in October 2017 that modified the April 2017 order. During 2017, Minnesota Power provided discounts of $8.6 million that were recorded as a receivable. In September 2017, Minnesota Power informed its EITE customers that it had suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing in September 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately $15 million annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, discounts provided to EITE customers will offset interim rate refund reserves for non-EITE customers. Minnesota Power provided $4.3 million of discounts to EITE customers during the three months ended March 31, 2018 ($2.3 million for the three months ended March 31, 2017).

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.

Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through at least December 31, 2032. No termination notice may be given for this contract prior to July 1, 2029. The wholesale electric service contracts with SWL&P and another municipal customer are effective through at least May 31, 2021, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided termination notice for its contract in 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. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.

Minnesota Power’s wholesale electric contracts with 14 municipal customers are effective through varying dates ranging from 2024 through 2029 with a majority effective through at least December 31, 2024. No termination notices may be given prior to three years before maturity. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will be determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates which allow Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. As a result of the MPUC approval of the certificate of need for the GNTL in 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission bill factor filings.

NOTE 6. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for investments and expenditures related to Bison and the restoration and repair of Thomson. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of certain renewable investments plus a return on the capital invested. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in a November 2017 order.

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 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 2016 order; however, implementation of the updated rates was delayed pending resolution of Minnesota Power’s 2016 general rate case based on a March 2017 MPUC order. On April 9, 2018, Minnesota Power filed an updated environmental improvement factor filing and requested to implement the updated billing rates to coincide with the implementation of final rates from its 2016 general rate case. (See 2016 Minnesota General Rate Case.) Upon approval of the filing and implementation of final rates from its 2016 general rate case, Minnesota Power will be authorized to include updated billing rates on customer bills.

Fuel Adjustment Clause Reform Pilot. In a December 2017 order, the MPUC adopted a three-year pilot program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order will change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forwarded-looking FAC with an annual prudence review and true-up to actual allowed costs. The MPUC is seeking input from Minnesota electric utilities and other stakeholders on the implementation and transition accounting needed to adopt the change. The three-year pilot program is expected to begin in 2019. In an order dated March 12, 2018, the MPUC affirmed determinations made at a hearing on January 18, 2018, at which the MPUC disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of the forward-looking fuel adjustment clause methodology in this proceeding resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in the fourth quarter of 2017.

Tax Cuts and Jobs Act of 2017. In December 2017, the MPUC opened a docket to review the effects of the TCJA on electric and natural gas rates and services in Minnesota, including the legislation’s impact on tax rates and utilities’ deferred income tax assets and liabilities. On March 2, 2018, Minnesota Power submitted an initial filing to the MPUC regarding the impacts of the TCJA on Minnesota Power. In this filing, Minnesota Power proposed to use the net tax benefits as an offset to other regulated costs, to the extent Minnesota Power is able to earn its allowed return on common equity, and flow the remainder of the benefits to customers through a new tax cost recovery rider. On April 20, 2018, Minnesota Power responded to intervenor comments requesting that the MPUC generally accept, with modifications and conditions, the DOC’s proposal to reduce the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 and use the benefits of the TCJA to offset the resulting increase in customer rates.

On January 10, 2018, the PSCW also opened a docket to review the effects of the TCJA and directed Wisconsin utilities to defer its impacts until further direction is provided by the PSCW. On February 9, 2018, SWL&P filed comments with the PSCW regarding the impacts of the TCJA on SWL&P. In this filing, SWL&P proposed deferring the benefits of the TCJA and incorporating any deferred refunds or credits into its next general rate case.

We have recorded the impact of the remeasurement of deferred income tax assets and liabilities in 2017 and the federal income tax rate change in 2018 resulting from the TCJA for Minnesota Power and SWL&P as regulatory assets and liabilities as the benefits of the TCJA are deferred pending the outcome of these regulatory proceedings. We are unable to predict the outcome of these regulatory proceedings.

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2017 PSCW retail rate order effective in August 2017 that allows for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 2017 were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity. On an annualized basis, SWL&P expects to collect additional revenue of $2.5 million under the 2017 PSCW retail rate order.

NOTE 6. REGULATORY MATTERS (Continued)

Integrated Resource Plan. In 2015, Minnesota Power filed its 2015 IRP with the MPUC which included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contained steps in Minnesota Power’s EnergyForward strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation in the next decade. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for Taconite Harbor, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. In 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired, which is expected to occur in the fourth quarter of 2018.

In July 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas energy PPA. These agreements are subject to MPUC approval of the construction of a 525 MW to 550 MW combined-cycle natural gas‑fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In a September 2017 order, the MPUC approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2019, and Minnesota Power’s request that approval for the natural gas energy PPA be decided through an administrative law judge process. A public hearing was held February 28, 2018, and public comments were due March 23, 2018. The administrative law judge is expected to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second half of 2018. The MPUC did not take any action regarding the wind and solar energy PPAs which will be refiled separately from the natural gas energy PPA.

Great Northern Transmission Line. Minnesota Power is constructing the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro. In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Transmission Cost Recovery Rider.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In a 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 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. To date, most of the right-of-way has been cleared, foundation installation and transmission tower assembly have commenced and tower construction is expected to begin in 2018. 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 $211.4 million have been incurred through March 31, 2018, of which $110.0 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 known as the Manitoba-Minnesota Transmission Project (MMTP) that will connect with the GNTL. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which remains pending. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP. The NEB determined that Manitoba Hydro’s application was complete in December 2017, and scheduled public hearings for this summer. The NEB is required to make a decision on the MMTP by March 2019 but is not precluded from making a decision prior to that date. Approval of the Canadian federal cabinet is also required. The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in-service requirements in PPAs with Minnesota Power, Manitoba Hydro has indicated that it would need to start construction of the MMTP in December 2018. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. Any significant delays in the MMTP construction schedule may result in Minnesota Power adjusting the GNTL construction schedule and impact the timing of capital expenditures and associated cost recovery under our transmission cost recovery rider.

NOTE 6. REGULATORY MATTERS (Continued)

Great Northern Transmission Line (Continued)

Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power that is to be transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be in service by early 2021.

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

Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved Camp Ripley, a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. Minnesota Power believes Camp Ripley and the community solar garden arrays will meet approximately one‑third of the overall mandate. Additionally, in a February 2017 order, 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. The proposal to incentivize customer‑sited solar installations and community solar garden subscriptions is expected to meet a portion of the required small scale solar mandate.

Regulatory Assets and Liabilities. Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

NOTE 6. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities (Continued)



Regulatory Assets and Liabilities	March 31, 2018		December 31, 2017
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans		$217.7		$220.3
Income Taxes	110.4		112.8
Asset Retirement Obligations	30.4		29.6
Manufactured Gas Plant	7.8		8.1
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	0.2		3.3
Other	4.5		5.6
Total Non-Current Regulatory Assets		$376.0		$384.7

Current Regulatory Liabilities (a)
Provision for Interim Rate Refund (b)		$28.1	—
Provision for Tax Reform Refund (c)	7.5		—
Total Current Regulatory Liabilities	35.6		—
Non-Current Regulatory Liabilities
Income Taxes	406.2			$411.2
Wholesale and Retail Contra AFUDC	59.1		57.9
Plant Removal Obligations	21.8		20.3
North Dakota Investment Tax Credits	14.3		14.1
Cost Recovery Riders	11.1		2.2
Provision for Interim Rate Refund (a)	—		23.7
Other	3.5		2.6
Total Non-Current Regulatory Liabilities	516.0		532.0
Total Regulatory Liabilities		$551.6		$532.0


(a)	Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.


(b)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $12.9 million of discounts provided to EITE customers that will be offset against interim rate refunds as of March 31, 2018 ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(c)	We have recorded the impact of the federal income tax rate change in 2018 due to the TCJA for Minnesota Power and SWL&P as regulatory liabilities and a reduction in revenue as the benefits of the TCJA are deferred pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Tax Cuts and Jobs Act of 2017.)

Investment in ATC

3 Months Ended

Mar. 31, 2018

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 portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of March 31, 2018, our equity investment in ATC was $120.1 million ($118.7 million at December 31, 2017). In the first three months of 2018, we invested $1.6 million in ATC, and on April 30, 2018, we invested an additional $2.3 million. We expect to make additional investments of $2.6 million in 2018.



ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2017		$118.7
Cash Investments	1.6
Equity in ATC Earnings	4.7
Distributed ATC Earnings	(5.2		)
Amortization of the Remeasurement of Deferred Income Taxes (a)	0.3
Equity Investment Balance as of March 31, 2018		$120.1

(a) Amortization related to the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

NOTE 7. INVESTMENT IN ATC (Continued)

In 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.

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

Short-Term and Long-Term Debt

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

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

SHORT-TERM AND LONG-TERM DEBT

The following tables present the Company’s short-term and long-term debt as of March 31, 2018, and December 31, 2017:



March 31, 2018	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$106.6	$(0.4)		$106.2
Long-Term Debt	1,405.6		(9.1)	1,396.5
Total Debt		$1,512.2	$(9.5)		$1,502.7



December 31, 2017	Principal		Unamortized Debt Issuance Costs	Total
Millions
Short-Term Debt		$64.6	$(0.5)		$64.1
Long-Term Debt	1,448.7		(9.5)	1,439.2
Total Debt		$1,513.3	$(10.0)		$1,503.3

On April 16, 2018, ALLETE issued and sold $60.0 million of its First Mortgage Bonds (the Bonds) that bear interest at 4.07 percent. The Bonds will mature in April 2048 and pay interest semi-annually in April and October of each year, commencing on October 16, 2018. ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. ALLETE intends to use the proceeds from the sale of the Bonds to fund utility capital investment and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of March 31, 2018, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of March 31, 2018, ALLETE was in compliance with its financial covenants.

Income Tax Expense

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax Expense [Text Block]

INCOME TAX EXPENSE



	Three Months Ended
	March 31,
	2018			2017
Millions
Current Income Tax Expense (a)
Federal	—			—
State		$0.7		$0.1
Total Current Income Tax Expense		$0.7		$0.1
Deferred Income Tax Expense (Benefit)
Federal (b)	$(6.8)				$7.3
State	2.6			5.9
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Income Tax Expense (Benefit)	$(4.4)				$13.0
Total Income Tax Expense (Benefit)	$(3.7)				$13.1


(a)	For the three months ended March 31, 2018, and 2017, 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.


(b)	For the three months ended March 31, 2018, the federal tax benefit is primarily due to the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA, and production tax credits.

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	2018			2017
Millions
Income Before Non-Controlling Interest and Income Taxes		$47.3			$62.1
Statutory Federal Income Tax Rate	21		%	35		%
Income Taxes Computed at Statutory Federal Rate		$9.9			$21.7
Increase (Decrease) in Income Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	2.6			3.9
Production Tax Credits	(14.4		)	(13.0		)
Regulatory Differences for Utility Plant	(2.5		)	0.1
Other	0.7			0.4
Total Income Tax Expense (Benefit)	$(3.7)				$13.1

For the three months ended March 31, 2018, the effective tax rate was a benefit of 7.8 percent (expense of 21.1 percent for the three months ended March 31, 2017).

Uncertain Tax Positions. As of March 31, 2018, we had gross unrecognized tax benefits of $1.7 million ($1.7 million as of December 31, 2017). Of the total gross unrecognized tax benefits, $0.8 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 2014, or state examination for years before 2013.

Reclassifications Out of Accumulated Other Comprehensive Loss	3 Months Ended
	Mar. 31, 2018
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, 2018, and 2017, 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, 2018, are presented on the Consolidated Statement of Shareholders’ Equity.

Earnings Per Share and Common Stock

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share and Common Stock [Text Block]

EARNINGS PER SHARE AND COMMON STOCK

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the three months ended March 31, 2018, and 2017, no options to purchase shares of ALLETE common stock were excluded from the computation of diluted earnings per share.



			2018					2017
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		$51.0			$51.0		$49.0			$49.0
Average Common Shares	51.2		0.2	51.4		50.2		0.2	50.4
Earnings Per Share		$1.00			$0.99		$0.97			$0.97

Pension and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Pension and Other Postretirement Benefit Plans [Text Block]

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS



	Pension						Other Postretirement
Components of Net Periodic Benefit Cost	2018			2017			2018			2017
Millions
Three Months Ended March 31,
Service Cost		$2.7			$2.5			$1.2			$1.1
Interest Cost (a)	7.4			8.1			1.8			1.9
Expected Return on Plan Assets (a)	(11.0		)	(10.6		)	(2.7		)	(2.6		)
Amortization of Prior Service Credits (a)	—			—			(0.4		)	(0.5		)
Amortization of Net Loss (a)	3.0			2.5			0.2			0.1
Net Periodic Benefit Cost		$2.1			$2.5			$0.1		—


(a)	These components of net periodic benefit cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.

Employer Contributions. For the three months ended March 31, 2018, we contributed $15.0 million in cash to the defined benefit pension plans ($1.7 million in cash and $13.5 million in ALLETE common stock for the three months ended March 31, 2017); we do not expect to make additional contributions to our defined benefit pension plans in 2018. For the three months ended March 31, 2018, and 2017, we made no contributions to our other postretirement benefit plans; we do not expect to make any contributions to our other postretirement benefit plans in 2018.

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2018

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 2017 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, 2018, Square Butte had total debt outstanding of $314.5 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, 2018, was $17.3 million ($20.3 million for the three months ended March 31, 2017). 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 ($2.3 million for the same period in 2017). 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 2018 and in 2017.

Oconto Electric Cooperative PSA. On March 6, 2018, Minnesota Power entered into a PSA with Oconto Electric Cooperative. The contract begins in January 2019 and is effective through May 2026. Under the PSA, Minnesota Power expects to provide approximately 25 MW of energy and capacity at fixed prices.

Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2018 and a portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018. The estimated minimum payments under these supply and transportation agreements is $21.5 million for the remainder of 2018, $1.8 million in 2019, and none thereafter. The costs of fuel and related transportation costs 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 a majority of terms expiring through 2024. The aggregate amount of minimum lease payments for all operating leases is $3.6 million for the remainder of 2018, $12.8 million in 2019, $9.5 million in 2020, $7.3 million in 2021, $6.1 million in 2022 and $30.0 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

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 is constructing the GNTL, an approximately 220‑mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Note 6. Regulatory Matters.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In a 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 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. To date, most of the right-of-way has been cleared, foundation installation and transmission tower assembly have commenced and tower construction is expected to begin in 2018. 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 $211.4 million have been incurred through March 31, 2018, of which $110.0 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 been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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

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

New Source Review (NSR). In 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in 2011 alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree, which was approved by the U.S. District Court for the District of Minnesota in 2014. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofitting or retiring 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 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as part of its EnergyForward strategic plan. We believe that costs to retire Boswell Units 1 and 2 will be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls but does require 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. 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 continued compliance with the CSAPR.

Mercury and Air Toxics Standards (MATS) Rule. Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The final MATS rule addressed such emissions from coal-fired utility units greater than 25 MW and established categories of HAPs, including mercury, trace metals other than mercury, and acid gases. The EPA established emission limits for these categories of HAPs and work practice standards for the remaining categories. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan to position the unit for MATS compliance was completed in 2015. Investments and compliance work previously completed at Boswell Unit 3, including emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to operate on natural gas in 2015 positioned those units for MATS compliance.

Minnesota Mercury Emissions Reduction Act/Rule. 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.

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. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.


•	Ozone NAAQS. 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 ground-level ozone continue in the state. No additional costs for compliance are anticipated at this time.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

•

Particulate Matter NAAQS. The EPA has 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 2016, environmental groups filed a lawsuit against the EPA in the U.S. District Court for the Northern District of California alleging the EPA had failed to fully implement the PM_2.5standards in certain states, including Minnesota, by not enforcing states’ submittals of required infrastructure implementation plans 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.


•	NO₂ NAAQS. Ambient monitoring data indicates that Minnesota is likely in compliance with the one-hour NAAQS standard for NO₂. In July 2017, the EPA proposed retaining the current one-hour and annual NO₂NAAQS. Additional compliance costs for the one-hour NO₂NAAQS are not expected at this time.

•

SO₂ NAAQS. 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 MPCA initially informed Minnesota Power that compliant SO₂ modeling completed at Minnesota Power's Boswell and Taconite Harbor facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also require facilities have federally-enforceable permit limits at which the one-hour SO₂NAAQS compliance was modeled by January 2017. Taconite Harbor was issued an amended air permit in 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 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. In August 2017, the EPA proposed retaining the current primary SO₂one-hour NAAQS. Compliance costs for the one-hour SO₂NAAQS are not expected to be material.

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 power supply;


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


•	Improving efficiency of our generating facilities;


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


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

EPA Regulation of GHG Emissions. In 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements, however, GHG requirements may be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

In 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established higher permitting thresholds for GHG than for other pollutants subject to PSD; however, the court also upheld the EPA’s ability to require best available control technology (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.

In 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.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation plan and a model rule for emissions trading. In 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In 2016, the U.S. Court of Appeals for the District of Columbia heard oral arguments and is currently deliberating. If the CPP is upheld at the completion of the appellate process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes. 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 filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in suspension while the EPA is reviewing the rule. In October 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. In December 2017, an Advanced Notice of Proposed Rulemaking (ANPRM) for a CPP replacement rule was published in the Federal Register.

Minnesota Power is currently evaluating the CPP rescission and recently proposed ANPRM for a CPP replacement rule as it relates to the State of Minnesota as well as its potential impact on the Company. Minnesota has already initiated several measures consistent with those called for under the CPP. Minnesota Power is implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 6. Regulatory Matters.)

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

Water. The Clean Water Act requires National Pollutant Discharge Elimination System (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 2014, EPA regulations under Section 316(b) of the Clean Water Act setting standards applicable to cooling water intake structures for the protection of aquatic organisms became effective. The regulations 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 will be implemented through NPDES permits issued to covered facilities. No NPDES permits for Minnesota Power facilities have been re-issued containing Section 316(b) requirements since the final rule became effective. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment indicates that Minnesota Power could incur costs of compliance up to $15 million over the next five years. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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 set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In September 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders bottom ash transport water and FGD wastewater provisions.

The final ELG rule’s potential impact on Minnesota Power operations is 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 discharge, but may do so in the future. Under the existing ELG rule, bottom ash transport water discharge must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. If FGD wastewater is discharged in the future, it will require additional wastewater treatment. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. 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.

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 reuse. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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

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

Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. 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. The EPA has indicated to Minnesota Power that the Taconite Harbor landfill is a CCR unit, based on the EPA’s interpretation of the CCR rule language. Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. In September 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA and on March 15, 2018, published the first phase of the proposed rule revisions in the federal register. Compliance costs, if any, for CCR at Taconite Harbor cannot be estimated at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Other Environmental Matters

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. In December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of March 31, 2018, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $8 million as of December 31, 2017), and a corresponding regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expect to incur these costs over the next four years.

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, 2018, ALLETE Clean Energy has $16.2 million outstanding in standby letters of credit.

U.S. Water Services. As of March 31, 2018, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of March 31, 2018, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. BNI Energy’s total reclamation liability is currently estimated at $47.5 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of March 31, 2018, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $8.6 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $6.1 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Community Development District Obligations. At March 31, 2018, we owned 70 percent of the assessable land in the Town Center District (70 percent at December 31, 2017) and 27 percent of the assessable land in the Palm Coast Park District (33 percent at December 31, 2017). At March 31, 2018, 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 $0.6 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, 2018

Segment Reporting [Abstract]

Business Segments [Text Block]

BUSINESS SEGMENTS

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

Regulated Operations includes three operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services is our integrated water management company. The ALLETE Clean Energy and U.S. Water Services reportable segments comprise our Energy Infrastructure and Related Services businesses. We also present Corporate and Other which includes two operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

NOTE 14. BUSINESS SEGMENTS (Continued)



	Three Months Ended
	March 31,
	2018			2017
Millions
Operating Revenue (a)
Regulated Operations
Residential		$40.7			$39.5
Commercial	36.6			38.2
Municipal	14.0			18.2
Industrial	114.9			121.7
Other Power Suppliers	43.7			41.2
Other	20.3			22.8
Total Regulated Operations	270.2			281.6

Energy Infrastructure and Related Services

ALLETE Clean Energy
Long-term PSA	18.6			17.8
Other	6.0			5.9
Total ALLETE Clean Energy	24.6			23.7

U.S. Water Services
Point-in-Time	22.3			21.8
Contract	9.5			8.9
Capital Project	6.4			1.4
Total U.S. Water Services	38.2			32.1

Corporate and Other
Long-term Contract	20.0			22.1
Other	5.2			6.1
Total Corporate and Other	25.2			28.2
Total Operating Revenue		$358.2			$365.6
Net Income (Loss)
Regulated Operations		$43.9			$43.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	8.1			6.7
U.S. Water Services	(1.4		)	(0.3		)

Corporate and Other	0.4			(0.9		)
Total Net Income		$51.0			$49.0


(a)	With the adoption of new revenue recognition guidance, the Company has enhanced the presentation of business segment Operating Revenue. (See Note 1. Operations and Significant Accounting Policies.)



	March 31, 2018		December 31, 2017
Millions
Assets
Regulated Operations		$3,877.0		$3,886.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	620.4		600.5
U.S. Water Services	287.4		292.4

Corporate and Other	287.3		300.5
Total Assets		$5,072.1		$5,080.0

Operations and Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Cash and Cash Equivalents, Policy [Policy Text Block]

We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Inventories – Net [Policy Text Block]

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

Subsequent Events [Policy Text Block]

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

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition for Alternative Revenue Programs, Policy [Policy Text Block]

New Accounting Standards [Policy Text Block]

New Accounting Pronouncements.

Recently Adopted Pronouncements

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

New Accounting Pronouncements (Continued)

Practical Expedients

The following practical expedients were used by the Company as part of the adoption of the new revenue recognition guidance:


•	We have a right to consideration from our customers in an amount that corresponds directly with the value to such customer for performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.


•	We do not adjust the promised amount of consideration for the effects of a significant financing component as at contract inception we expect that the period between when we transfer a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Where applicable, we adopted this guidance using the portfolio approach in which contracts that have similar characteristics were reviewed as a portfolio. The effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying the guidance to each individual contract.


•	We recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that would otherwise have been recognized is one year or less.

Recently Issued Pronouncements

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, 2018, and 2017.

Available-for-sale Investments [Policy Text Block]

We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities.

Acquisitions [Policy Text Block]

Fair Value Measurement [Policy Text Block]

We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy.

Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.

Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.

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]

Uncertain Tax Positions [Policy Text Block]

The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

Earnings Per Share [Policy Text Block]

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]

Business Segments [Policy Text Block]

Operations and Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Cash, Cash Equivalents and Restricted Cash [Table Text Block]

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amount presented in the Consolidated Statement of Cash Flows. During the first quarter of 2018, the Company updated the presentation of its Consolidated Statement of Cash Flows to include restricted cash 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. (See Recently Adopted Pronouncements - Statement of Cash Flows: Restricted Cash.)



Cash, Cash Equivalents and Restricted Cash	March 31, 2018		December 31, 2017		March 31, 2017		December 31, 2016
Millions
Cash and Cash Equivalents		$98.5		$98.9		$81.8		$27.5
Restricted Cash included in Prepayments and Other	8.8		2.6		9.1		2.2
Restricted Cash included in Other Non-Current Assets	8.6		8.6		8.6		8.6
Cash, Cash Equivalents and Restricted Cash in the Consolidated Statement of Cash Flows		$115.9		$110.1		$99.5		$38.3

Inventories – Net [Table Text Block]



Inventories – Net	March 31, 2018			December 31, 2017
Millions
Fuel (a)		$33.8			$34.8
Materials and Supplies	46.9			46.5
Construction of Wind Energy Facility (b)	46.9			—
Raw Materials	2.8			2.8
Work in Progress	4.2			4.2
Finished Goods	9.3			8.3
Reserve for Obsolescence	(0.8		)	(0.7		)
Total Inventories – Net		$143.1			$95.9


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


(b)	On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project value from Property, Plant and Equipment – Net to Inventory – Net as ALLETE Clean Energy will no longer own and operate the facility upon completion.

Other Non-Current Assets [Table Text Block]



Other Non-Current Assets	March 31, 2018		December 31, 2017
Millions
Contract Assets (a)		$31.0		$31.6
Finance Receivable	10.9		11.0
Other	67.1		65.1
Total Other Non-Current Assets		$109.0		$107.7


(a)	Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements.

Other Current Liabilities [Table Text Block]



Other Current Liabilities	March 31, 2018		December 31, 2017
Millions
Provision for Interim Rate Refund (a)		$28.1	—
PSAs	21.5			$24.5
Contract Liabilities (b)	20.0		8.7
Provision for Tax Reform Refund (c)	7.5		—
Contingent Consideration (d)	5.5		—
Other	47.6		50.0
Total Other Current Liabilities		$130.2		$83.2


(a)	Provision for Interim Rate Refund is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019. (See Note 6. Regulatory Matters.)


(b)	Contract Liabilities include deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.


(c)	Provision for Tax Reform Refund is deferred as a regulatory liability pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Note 6. Regulatory Matters.)


(d)	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, 2018		December 31, 2017
Millions
Asset Retirement Obligation		$122.9		$122.7
PSAs	86.3		89.5
Contingent Consideration (a)	—		5.4
Other	48.6		49.5
Total Other Non-Current Liabilities		$257.8		$267.1


(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,	2018		2017
Millions
Cash Paid for Interest – Net of Amounts Capitalized		$19.3		$18.9
Noncash Investing and Financing Activities
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment	$(48.1)		$(3.5)
Reclassification of Property, Plant and Equipment to Inventory (a)		$46.9	—
Capitalized Asset Retirement Costs		$0.8		$19.3
AFUDC–Equity		$0.3		$0.2
ALLETE Common Stock Contributed to the Pension Plans	—			$13.5


(a)	On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project value from Property, Plant and Equipment – Net to Inventory – Net as ALLETE Clean Energy will no longer own and operate the facility upon completion.

Acquisitions (Table)

3 Months Ended

Mar. 31, 2018

Tonka Water [Member]

Business Acquisition [Line Items]

Schedule of Business Acquisitions [Table Text Block]



Millions
Assets Acquired
Accounts Receivable		$5.1
Other Current Assets	5.1
Trade Names (a)	0.9
Goodwill (a)(b)	16.9
Other Non-Current Assets	0.2
Total Assets Acquired		$28.2
Liabilities Assumed
Current Liabilities		$9.0
Total Liabilities Assumed		$9.0
Net Identifiable Assets Acquired		$19.2

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


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

Fair Value (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Recurring Fair Value Measures [Table Text Block]



	Fair Value as of December 31, 2017
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$10.2	—		—			$10.2
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.9	—		8.9
Cash Equivalents	3.8		—		—		3.8
Total Fair Value of Assets		$14.0		$8.9	—			$22.9

Liabilities (b)
Deferred Compensation	—			$18.2	—			$18.2
U.S. Water Services Contingent Consideration	—		—			$5.4	5.4
Total Fair Value of Liabilities	—			$18.2		$5.4		$23.6
Total Net Fair Value of Assets (Liabilities)		$14.0	$(9.3)		$(5.4)		$(0.7)


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


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



	Fair Value as of March 31, 2018
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities		$12.4	—		—			$12.4
Available-for-sale – Corporate and Governmental Debt Securities	—			$8.7	—		8.7
Cash Equivalents	2.0		—		—		2.0
Total Fair Value of Assets		$14.4		$8.7	—			$23.1

Liabilities
Deferred Compensation (b)	—			$20.2	—			$20.2
U.S. Water Services Contingent Consideration (c)	—		—			$5.5	5.5
Total Fair Value of Liabilities	—			$20.2		$5.5		$25.7
Total Net Fair Value of Assets (Liabilities)		$14.4	$(11.5)		$(5.5)		$(2.6)


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


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


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

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



Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2017		$5.4
Accretion	0.1
Balance as of March 31, 2018		$5.5

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, 2018	$1,512.2	$1,583.1
December 31, 2017	$1,513.3	$1,627.6

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2018

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Table Text Block]



Regulatory Assets and Liabilities	March 31, 2018		December 31, 2017
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans		$217.7		$220.3
Income Taxes	110.4		112.8
Asset Retirement Obligations	30.4		29.6
Manufactured Gas Plant	7.8		8.1
PPACA Income Tax Deferral	5.0		5.0
Conservation Improvement Program	0.2		3.3
Other	4.5		5.6
Total Non-Current Regulatory Assets		$376.0		$384.7

Current Regulatory Liabilities (a)
Provision for Interim Rate Refund (b)		$28.1	—
Provision for Tax Reform Refund (c)	7.5		—
Total Current Regulatory Liabilities	35.6		—
Non-Current Regulatory Liabilities
Income Taxes	406.2			$411.2
Wholesale and Retail Contra AFUDC	59.1		57.9
Plant Removal Obligations	21.8		20.3
North Dakota Investment Tax Credits	14.3		14.1
Cost Recovery Riders	11.1		2.2
Provision for Interim Rate Refund (a)	—		23.7
Other	3.5		2.6
Total Non-Current Regulatory Liabilities	516.0		532.0
Total Regulatory Liabilities		$551.6		$532.0


(a)	Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.


(b)	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $12.9 million of discounts provided to EITE customers that will be offset against interim rate refunds as of March 31, 2018 ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)


(c)	We have recorded the impact of the federal income tax rate change in 2018 due to the TCJA for Minnesota Power and SWL&P as regulatory liabilities and a reduction in revenue as the benefits of the TCJA are deferred pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Tax Cuts and Jobs Act of 2017.)

Income Tax Expense (Tables)

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax Expense [Table Text Block]



	Three Months Ended
	March 31,
	2018			2017
Millions
Current Income Tax Expense (a)
Federal	—			—
State		$0.7		$0.1
Total Current Income Tax Expense		$0.7		$0.1
Deferred Income Tax Expense (Benefit)
Federal (b)	$(6.8)				$7.3
State	2.6			5.9
Investment Tax Credit Amortization	(0.2		)	(0.2		)
Total Deferred Income Tax Expense (Benefit)	$(4.4)				$13.0
Total Income Tax Expense (Benefit)	$(3.7)				$13.1


(a)	For the three months ended March 31, 2018, and 2017, 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.


(b)	For the three months ended March 31, 2018, the federal tax benefit is primarily due to the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA, and production tax credits.

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	2018			2017
Millions
Income Before Non-Controlling Interest and Income Taxes		$47.3			$62.1
Statutory Federal Income Tax Rate	21		%	35		%
Income Taxes Computed at Statutory Federal Rate		$9.9			$21.7
Increase (Decrease) in Income Tax Due to:
State Income Taxes – Net of Federal Income Tax Benefit	2.6			3.9
Production Tax Credits	(14.4		)	(13.0		)
Regulatory Differences for Utility Plant	(2.5		)	0.1
Other	0.7			0.4
Total Income Tax Expense (Benefit)	$(3.7)				$13.1

Pension and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

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



	Pension						Other Postretirement
Components of Net Periodic Benefit Cost	2018			2017			2018			2017
Millions
Three Months Ended March 31,
Service Cost		$2.7			$2.5			$1.2			$1.1
Interest Cost (a)	7.4			8.1			1.8			1.9
Expected Return on Plan Assets (a)	(11.0		)	(10.6		)	(2.7		)	(2.6		)
Amortization of Prior Service Credits (a)	—			—			(0.4		)	(0.5		)
Amortization of Net Loss (a)	3.0			2.5			0.2			0.1
Net Periodic Benefit Cost		$2.1			$2.5			$0.1		—


(a)	These components of net periodic benefit cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.

Business Segments (Tables)

3 Months Ended

Mar. 31, 2018

Segment Reporting [Abstract]

Business Segments [Table Text Block]



	Three Months Ended
	March 31,
	2018			2017
Millions
Operating Revenue (a)
Regulated Operations
Residential		$40.7			$39.5
Commercial	36.6			38.2
Municipal	14.0			18.2
Industrial	114.9			121.7
Other Power Suppliers	43.7			41.2
Other	20.3			22.8
Total Regulated Operations	270.2			281.6

Energy Infrastructure and Related Services

ALLETE Clean Energy
Long-term PSA	18.6			17.8
Other	6.0			5.9
Total ALLETE Clean Energy	24.6			23.7

U.S. Water Services
Point-in-Time	22.3			21.8
Contract	9.5			8.9
Capital Project	6.4			1.4
Total U.S. Water Services	38.2			32.1

Corporate and Other
Long-term Contract	20.0			22.1
Other	5.2			6.1
Total Corporate and Other	25.2			28.2
Total Operating Revenue		$358.2			$365.6
Net Income (Loss)
Regulated Operations		$43.9			$43.5

Energy Infrastructure and Related Services
ALLETE Clean Energy	8.1			6.7
U.S. Water Services	(1.4		)	(0.3		)

Corporate and Other	0.4			(0.9		)
Total Net Income		$51.0			$49.0


(a)	With the adoption of new revenue recognition guidance, the Company has enhanced the presentation of business segment Operating Revenue. (See Note 1. Operations and Significant Accounting Policies.)



	March 31, 2018		December 31, 2017
Millions
Assets
Regulated Operations		$3,877.0		$3,886.6

Energy Infrastructure and Related Services
ALLETE Clean Energy	620.4		600.5
U.S. Water Services	287.4		292.4

Corporate and Other	287.3		300.5
Total Assets		$5,072.1		$5,080.0

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

Mar. 31, 2018

Dec. 31, 2017

Mar. 31, 2017

Dec. 31, 2016

Cash, Cash Equivalents and Restricted Cash [Abstract]

Cash and Cash Equivalents

$ 98.5

$ 98.9

$ 81.8

$ 27.5

Restricted Cash included in Prepayments and Other

8.8

2.6

9.1

2.2

Restricted Cash included in Other Non-Current Assets

8.6

Total Cash, Cash Equivalents and Restricted Cash

115.9

110.1

$ 99.5

$ 38.3

Inventories – Net [Abstract]

Fuel

^[1]

33.8

34.8

Materials and Supplies

46.9

46.5

Construction of Wind Energy Facility

^[2]

46.9

0.0

Raw Materials

2.8

Work in Progress

4.2

Finished Goods

9.3

8.3

Reserve for Obsolescence

(0.8)

(0.7)

Total Inventories – Net

143.1

95.9

Other Non-Current Assets [Abstract]

Contract Assets

^[3]

31.0

31.6

Finance Receivable

10.9

11.0

Total Other Non-Current Assets

67.1

65.1

109.0

107.7

Other Current Liabilites [Abstract]

Provision for Interim Rate Refund

^[4]

28.1

0.0

PSAs

21.5

24.5

Contract Liabilities

^[5]

20.0

8.7

Provision for Tax Reform Refunds

^[6]

7.5

0.0

Contingent Consideration - Current

^[7]

5.5

0.0

Total Other Current Liabilities

47.6

50.0

130.2

83.2

Other Non-Current Liabilities [Abstract]

Asset Retirement Obligation

122.9

122.7

PSAs

86.3

89.5

Contingent Consideration - Non-current

^[8]

0.0

5.4

Total Other Non-Current Liabilities

48.6

49.5

$ 257.8

$ 267.1

[1]	Fuel consists primarily of coal inventory at Minnesota Power.
[2]	On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project value from Property, Plant and Equipment – Net to Inventory – Net as ALLETE Clean Energy will no longer own and operate the facility upon completion.
[3]	Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements.
[4]	Provision for Interim Rate Refund is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019. (See Note 6. Regulatory Matters.)
[5]	Contract Liabilities include deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.
[6]	Provision for Tax Reform Refund is deferred as a regulatory liability pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Note 6. Regulatory Matters.)
[7]	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.)
[8]	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, 2018

Mar. 31, 2017

Supplemental Cash Flow Information [Abstract]

Cash Paid for Interest – Net of Amounts Capitalized

$ 19.3

$ 18.9

Noncash Investing and Financing Activities [Abstract]

Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment

(48.1)

(3.5)

Reclassification of Property, Plant and Equipment to Inventory

^[1]

46.9

0.0

Capitalized Asset Retirement Costs

0.8

19.3

AFUDC–Equity

0.3

0.2

ALLETE Common Stock Contributed to the Pension Plans

$ 0.0

$ 13.5

[1]

On February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project value from Property, Plant and Equipment – Net to Inventory – Net as ALLETE Clean Energy will no longer own and operate the facility upon completion.

Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Details)	3 Months Ended
	Mar. 31, 2018 Customers MW
Regulated Operations [Member] \| Alternative Programs [Member]
Disaggregation of Revenue [Line Items]
Revenue Collection Period Following the Annual Period it is Recognized	24 months
Regulated Operations [Member] \| Municipal [Member] \| Municipal Customers [Member] \| Wholesale Electric [Member] \| Long-term Contract with Customer [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	16
Length of Notice Required to Terminate Contract	three-year
Regulated Operations [Member] \| Industrial [Member] \| Industrial Customers [Member] \| Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Percentage of Total Regulated Utility kWh Sales	49.00%
Regulated Operations [Member] \| Industrial [Member] \| Industrial Customers [Member] \| Retail Electric [Member] \| Long-term Contract with Customer [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	four-year
Number of Large Power Customer Contracts	9
Large Power Customer Contract Serving Requirement \| MW	10
Regulated Operations [Member] \| Other Power Suppliers [Member] \| Other Power Supplier Customers [Member] \| Sale of Energy under PSA [Member] \| Long-term Contract with Customer [Member]
Disaggregation of Revenue [Line Items]
Number of Customers	2
U.S. Water Services [Member] \| Contract [Member] \| Chemicals, Consumable Equipment and Services [Member]
Disaggregation of Revenue [Line Items]
Length of Notice Required to Terminate Contract	30-day

Operations and Significant Accounting Policies - Revenue - Nature of Revenue Streams (Continued) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Payment Terms and Conditions	Payment terms and conditions vary across our businesses. Aside from our taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered or goods provided. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates.
Regulated Operations [Member] \| Industrial Customers [Member] \| Long-term Contract with Customer [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 70
Expected Period to Recognize Minimum Revenue	1 year
Regulated Operations [Member] \| Industrial Customers [Member] \| Long-term Contract with Customer [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 70
Expected Period to Recognize Minimum Revenue	1 year
Regulated Operations [Member] \| Industrial Customers [Member] \| Long-term Contract with Customer [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 50
Expected Period to Recognize Minimum Revenue	1 year
Regulated Operations [Member] \| Industrial Customers [Member] \| Long-term Contract with Customer [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 50
Expected Period to Recognize Minimum Revenue	1 year
Regulated Operations [Member] \| Industrial Customers [Member] \| Long-term Contract with Customer [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 30
Expected Period to Recognize Minimum Revenue	1 year
Regulated Operations [Member] \| Industrial Customers [Member] \| Long-term Contract with Customer [Member] \| Industrial [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 30
Expected Period to Recognize Minimum Revenue	4 years
Regulated Operations [Member] \| Other Power Supplier Customers [Member] \| Long-term Contract with Customer [Member] \| Other Power Suppliers [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 10
Expected Period to Recognize Minimum Revenue	1 year
Regulated Operations [Member] \| Other Power Supplier Customers [Member] \| Long-term Contract with Customer [Member] \| Other Power Suppliers [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 10
Expected Period to Recognize Minimum Revenue	1 year

Operations and Significant Accounting Policies - Revenue - Assets Recognized From the Costs to Obtain a Contract with a Customer (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Contract with Customer, Asset, Net, Noncurrent	$ 31.0		$ 31.6
Contract Asset Non-Cash Amortization	$ 0.6	$ 0.6

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

3 Months Ended

Mar. 31, 2017

Mar. 31, 2018

Dec. 31, 2017

Cumulative Effect of New Accounting Principle in Period of Adoption

^[1]

$ 0.5

Operating Leases, Future Minimum Payments Due

$ 80.0

Accounting Standards Update 2018-02 [Member]

Cumulative Effect of New Accounting Principle in Period of Adoption

5.7

Accounting Standards Update 2017-07 [Member] | Operating and Maintenance [Member]

Accounting Standards Update 2017-07 [Member] | Cost of Sales - Non-utility [Member]

$ 1.1

Accounting Standards Update 2017-07 [Member] | Other Income/Expense [Member]

0.1

Accounting Standards Update 2016-01 [Member]

1.0

Cumulative Effect of New Accounting Principle in Period of Adoption

0.1

Accounting Standards Update 2016-18 [Member]

Accounting Standards Update 2014-09 [Member]

$ 6.9

Cumulative Effect of New Accounting Principle in Period of Adoption

$ 0.5

[1]

Operations and Significant Accounting Policies - Reclassification of Prior Income Statement (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Operating Revenue to Operating Revenue – Utility [Member]
Reclassification of Prior Income Statement [Line Items]
Prior Period Reclassification Amount	$ 281.6
Operating Revenue – Non-utility [Member]
Reclassification of Prior Income Statement [Line Items]
Prior Period Reclassification Amount	84.0
Cost of Sales to Fuel, Purchased Power and Gas – Utility [Member]
Reclassification of Prior Income Statement [Line Items]
Prior Period Reclassification Amount	$ 3.6

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

Available-for-sale Securities

ALLETE Properties

$ 26.0

$ 26.4

21.1

^[1]

19.1

2.0

3.8

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

3.7

3.8

Total Other Investments

52.8

$ 53.1

One Year or Less

0.9

One Year to Less Than Three Years

3.4

Three Years to Less Than Five Years

3.3

Five or More Years

1.1

Impairment of Land Inventory

$ 0.0

[1]

As of March 31, 2018, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.9 million, in one year to less than three years was $3.4 million, in three years to less than five years was $3.3 million and in five or more years was $1.1 million.

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

Sep. 01, 2017

Mar. 31, 2018

Dec. 31, 2017

Assets Acquired [Abstract]

Goodwill

$ 148.3

Tonka Water [Member]

Business Acquisition [Line Items]

Percentage of Voting Interests Acquired

100.00%

Name of Acquired Entity

Tonka Water

Total Consideration

$ 19.2

Cash Payment to Acquire Business

19.0

Working Capital Adjustment Paid in the Fourth Quarter 2017

0.2

Assets Acquired [Abstract]

Accounts Receivable

5.1

Other Current Assets

5.1

Trade Names

^[1]

0.9

Goodwill

^[1],[2]

16.9

Other Non-Current Assets

0.2

Total Assets Acquired

28.2

Liabilities Assumed [Abstract]

Current Liabilities

9.0

Total Liabilities Assumed

9.0

Net Identifiable Assets Acquired

19.2

Tax Deductible Goodwill

$ 4.1

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

Goodwill and Intangible Assets - Goodwill (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 148.3		$ 148.3
Amortization of Intangible Assets	$ 1.4	$ 1.4

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

Definite-Lived Intangible Assets [Roll Forward]

$ 61.0

Amortization

(1.4)

$ (1.4)

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

59.6

Accumulated Amortization

16.2

$ 14.8

4.0

4.9

4.7

4.6

4.3

37.1

Intangible Assets [Abstract]

Total Intangible Assets

76.2

$ 77.6

Total Intangible Assets, Amortization

$ (1.4)

Weighted Average [Member]

Definite-Lived Intangible Assets [Roll Forward]

Trademarks and Trade Names [Member]

18 years

Indefinite-Lived Intangible Assets [Roll Forward]

$ 16.6

Customer Relationships [Member]

16.6

Definite-Lived Intangible Assets [Roll Forward]

54.7

Amortization

(1.1)

$ 53.6

Total Intangible Assets, Amortization

20 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]

1 year

Definite-Lived Intangible Assets [Roll Forward]

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

11 years

Definite-Lived Intangible Assets [Roll Forward]

7 years

[1]	Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.

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

3 Months Ended

12 Months Ended

Mar. 31, 2018

Dec. 31, 2017

Recurring Fair Value Measures [Member]

$ 2.0

$ 3.8

Available-for-sale – Corporate and Governmental Debt Securities

12.4

^[1]

10.2

^[2]

8.7

^[1]

8.9

^[2]

2.0

^[1]

3.8

^[2]

23.1

22.9

20.2

^[3]

18.2

^[4]

5.5

^[5]

5.4

^[4]

25.7

23.6

Fair Value Hierarchy Transfers, All Levels

(2.6)

(0.7)

Activity in Level 3 [Roll Forward]

0.0

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

Available-for-sale – Corporate and Governmental Debt Securities

12.4

^[1]

10.2

^[2]

0.0

^[1]

0.0

^[2]

2.0

^[1]

3.8

^[2]

14.4

14.0

0.0

^[3]

0.0

^[4]

0.0

^[5]

0.0

^[4]

0.0

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

14.4

14.0

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[1]

0.0

^[2]

8.7

^[1]

8.9

^[2]

0.0

^[1]

0.0

^[2]

8.7

8.9

20.2

^[3]

18.2

^[4]

0.0

^[5]

0.0

^[4]

20.2

18.2

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

(11.5)

(9.3)

Available-for-sale – Corporate and Governmental Debt Securities

0.0

^[1]

0.0

^[2]

0.0

^[1]

0.0

^[2]

0.0

^[1]

0.0

^[2]

0.0

0.0

^[3]

0.0

^[4]

5.5

^[5]

5.4

^[4]

5.5

5.4

(5.5)

(5.4)

Activity in Level 3 [Roll Forward]

5.4

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

5.5

$ 5.4

Activity in Level 3 [Roll Forward]

Activity in Level 3

$ 0.1

[1]	Included in Other Investments on the Consolidated Balance Sheet.
[2]	Included in Other Investments on the Consolidated Balance Sheet.
[3]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[4]	Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
[5]	Included in Other Current Liabilities on the Consolidated Balance Sheet.

Fair Value - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Carrying Amount	$ 1,512.2	$ 1,513.3
Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Long-Term Debt, Including Long-Term Debt Due Within One Year - Fair Value	$ 1,583.1	$ 1,627.6

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, 2018	Dec. 31, 2017
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Abstract]
Indicators of Impairment	$ 0.0	$ 0.0

Regulatory Matters - Electric Rates (Details) $ in Millions					1 Months Ended		3 Months Ended		12 Months Ended
Regulatory Matters - Electric Rates (Details) $ in Millions	Apr. 02, 2018 USD ($)	Jan. 18, 2018 USD ($)	Aug. 09, 2017	Apr. 13, 2017 USD ($)	Dec. 31, 2016 USD ($)	Nov. 30, 2016 USD ($)	Mar. 31, 2018 USD ($) Customers Years MW	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)
Regulatory Matters [Line Items]
Pre-Tax Charge to Fuel, Purchase Power and Gas - Utility							$ 100.9	$ 96.6
MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Pre-Tax Charge to Fuel, Purchase Power and Gas - Utility									$ 19.5
MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Boswell Energy Center [Member]
Regulatory Matters [Line Items]
Expected Decrease in Annual Depreciation Expense							25.0
PSCW [Member] \| 2016 Wisconsin General Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity			10.50%
Approved Equity Ratio			55.00%
Expected Annualized Collection of Additional Revenue Under Retail Rate Order							$ 2.5
PSCW [Member] \| 2012 Wisconsin Rate Case [Member] \| SWL&P [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Approved Return on Common Equity							10.90%
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							$ 24.1	24.2
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Requested Average Rate Increase						9.00%
Requested Return on Equity						10.25%
Requested Equity Ratio						53.81%
Annual Additional Revenue Generated from Requested Final Rate Increase		$ 13.0				$ 55.0
Annual Additional Revenue Generated from Requested Interim Rate Increase				$ 32.2	$ 34.7	49.0
Annual Additional Revenue Generated from Requested Final Rate Increase, Amended						$ 49.0
Approved Return on Common Equity		9.25%
Approved Equity Ratio		53.81%
Reserve for Interim Rate Refund							41.0		32.0
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Minimum [Member] \| Subsequent Event [Member]
Regulatory Matters [Line Items]
Requested Reconsideration of Certain Decisions Representing Annualized Additional Revenue	$ 20.0
Electric Rates [Member] \| MPUC [Member] \| 2016 Minnesota General Rate Case [Member] \| Minnesota Power [Member] \| Retail Customers [Member] \| Maximum [Member] \| Subsequent Event [Member]
Regulatory Matters [Line Items]
Requested Reconsideration of Certain Decisions Representing Annualized Additional Revenue	$ 25.0
Electric Rates [Member] \| MPUC [Member] \| Energy-Intensive Trade-Exposed Customer Rates [Member] \| Minnesota Power [Member] \| Retail Customers [Member]
Regulatory Matters [Line Items]
Provided Discounts to EITE Customers							4.3	$ 2.3	$ 8.6
Expected Discounts to EITE Customers Annually							$ 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
Length of 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 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] \| FERC [Member] \| FERC-Approved Wholesale Rates [Member] \| Minnesota Power [Member] \| Municipal Customers [Member] \| Wholesale Electric Contracts (Expire from 2024 through 2029) [Member]
Regulatory Matters [Line Items]
Number of Customers \| Customers							14

Regulatory Matters - Integrated Resource Plan (Details) - MPUC [Member] - MW	Jul. 28, 2017	Dec. 31, 2016
Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Output Being Purchased (MW)	250
Natural Gas-fired [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Natural Gas PPA [Member]
Regulatory Matters [Line Items]
Expected Output Entitlement (Percent)	50.00%
Natural Gas-fired [Member] \| Minimum [Member] \| Resource Package [Member] \| Jointly Owned by ALLETE and Dairyland Power Cooperative [Member] \| Natural Gas PPA [Member] \| Combined-Cycle Natural Gas-fired Generating Facility [Member] \| Jointly Owned Electricity Generation Plant [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Jointly Owned (MW)	525
Natural Gas-fired [Member] \| Minimum [Member] \| Minnesota Power [Member] \| Integrated Resource Plan [Member]
Regulatory Matters [Line Items]
Additional Natural Gas-fired Generation (MW)		200
Natural Gas-fired [Member] \| Maximum [Member] \| Resource Package [Member] \| Jointly Owned by ALLETE and Dairyland Power Cooperative [Member] \| Natural Gas PPA [Member] \| Combined-Cycle Natural Gas-fired Generating Facility [Member] \| Jointly Owned Electricity Generation Plant [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Jointly Owned (MW)	550
Natural Gas-fired [Member] \| Maximum [Member] \| Minnesota Power [Member] \| Integrated Resource Plan [Member]
Regulatory Matters [Line Items]
Additional Natural Gas-fired Generation (MW)		300
Wind Turbine Generators [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Tenaska [Member] \| Tenaska PPA [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)	250
Solar Energy Generation [Member] \| Minnesota Power [Member] \| Resource Package [Member] \| Solar Energy PPA [Member]
Regulatory Matters [Line Items]
Generating Capacity to be Counterparty Owned (MW)	10

Regulatory Matters - Great Northern Transmission Line (Details) - Great Northern Transmission Line [Member] $ in Millions	Mar. 31, 2018 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	$ 211.4
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	$ 110.0
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, 2018
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, 2018 MW
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
Minimum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Overall Mandate Percentage	1.50%
Minnesota Solar Energy Standard - Small Scale Solar Mandate Percentage	10.00%
Maximum [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Qualifying Capacity for Small Scale Solar Mandate (MW)	0.04
Minnesota Solar Energy Standard [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Minnesota Solar Energy Standard - Percentage of Overall Mandate Expected to be Met with Current Filings or Projects	33.00%
Minnesota Solar Energy Standard - Camp Ripley Project [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	10
Minnesota Solar Energy Standard - Community Solar Garden Project - Purchased Output [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Counterparty Owned (MW)	1
Minnesota Solar Energy Standard - Community Solar Garden Project - Owned and Operated [Member] \| Minnesota Power [Member]
Regulatory Matters [Line Items]
Generating Capacity Owned (MW)	0.04

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

3 Months Ended

Mar. 31, 2018

Dec. 31, 2017

Regulatory Assets and Liabilities Currently Earning a Return

No regulatory assets or liabilities are currently earning a return.

Current Regulatory Liabilities

$ 376.0

$ 384.7

^[1]

35.6

0.0

Total Regulatory Liabilities

516.0

532.0

551.6

532.0

Minnesota Power [Member] | Retail Customers [Member] | Electric Rates [Member] | Energy-Intensive Trade-Exposed Customer Rates [Member]

Provided Discounts to EITE Customers that will be Offset Against Interim Rate Refunds

12.9

MPUC [Member] | Minnesota Power [Member] | Retail Customers [Member] | Electric Rates [Member] | Energy-Intensive Trade-Exposed Customer Rates [Member]

Provided Discounts to EITE Customers that will be Offset Against Interim Rate Refunds

8.6

Provision for Interim Rate Refund [Domain]

Current Regulatory Liabilities

^[1],[2]

28.1

0.0

Provision for Tax Reform Refund [Domain]

Current Regulatory Liabilities

^[1],[3]

7.5

0.0

Income Taxes [Member]

Wholesale and Retail Contra AFUDC [Member]

406.2

411.2

Plant Removal Obligations [Member]

59.1

57.9

North Dakota Investment Tax Credits [Member]

21.8

20.3

Cost Recovery Riders [Member]

14.3

14.1

Provision for Interim Rate Refund [Member]

11.1

2.2

^[2]

0.0

23.7

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

3.5

2.6

217.7

220.3

Income Taxes [Member]

Asset Retirement Obligations [Member]

110.4

112.8

Manufactured Gas Plant [Member]

30.4

29.6

PPACA Income Tax Deferral [Member]

7.8

8.1

Conservation Improvement Program [Member]

5.0

0.2

3.3

$ 4.5

$ 5.6

[1]	Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.
[2]	This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes $12.9 million of discounts provided to EITE customers that will be offset against interim rate refunds as of March 31, 2018 ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)
[3]	We have recorded the impact of the federal income tax rate change in 2018 due to the TCJA for Minnesota Power and SWL&P as regulatory liabilities and a reduction in revenue as the benefits of the TCJA are deferred pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Tax Cuts and Jobs Act of 2017.)

Investment in ATC (Details) - USD ($)
$ in Millions

3 Months Ended

Apr. 30, 2018

Mar. 31, 2018

Mar. 31, 2017

Equity Investment Balance as of December 31, 2017

$ 118.7

Cash Investments

1.6

$ 3.1

Equity in ATC Earnings

4.7

$ 6.1

Equity Investment Balance as of March 31, 2018

$ 120.1

FERC [Member] | Return on Equity Complaint 2 [Member]

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 2018

$ 2.6

Equity Investment Balance as of December 31, 2017

118.7

Cash Investments

1.6

Equity in ATC Earnings

4.7

Distributed ATC Earnings

(5.2)

Amortization of the Remeasurement of Deferred Income Taxes

^[1]

0.3

Equity Investment Balance as of March 31, 2018

$ 120.1

Authorized Return on Equity

10.32%

Authorized Return on Equity, Including Incentive Adder

10.82%

ATC [Member] | Subsequent Event [Member]

Current Income Tax Expense [Abstract]

Cash Investments

$ 2.3

[1]	Amortization related to the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.

Short-Term and Long-Term Debt (Details) - USD ($) $ in Millions	Apr. 16, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Short-Term Debt - Principal		$ 106.6	$ 64.6
Short-Term Debt - Unamortized Debt Issuance Costs		(0.4)	(0.5)
Short-Term Debt - Total		106.2	64.1
Long-Term Debt - Principal		1,405.6	1,448.7
Long-Term Debt - Unamortized Debt Issuance Costs		(9.1)	(9.5)
Long-Term Debt - Total		1,396.5	1,439.2
Total Debt - Principal		1,512.2	1,513.3
Total Debt - Unamortized Debt Issuance Costs		(9.5)	(10.0)
Total Debt - Total		$ 1,502.7	$ 1,503.3
ALLETE First Mortgage Bonds 4.07% Due April 2048 [Member] \| Subsequent Event [Member]
Debt Instrument [Line Items]
First Mortgage Bonds - Proceeds from Sale	$ 60.0
First Mortgage Bonds - Interest Rate	4.07%

Short-Term and Long-Term Debt - Financial Covenants (Details)	Mar. 31, 2018
Debt Instrument [Line Items]
Actual Ratio of Indebtedness to Total Capitalization	0.42
Maximum [Member]
Debt Instrument [Line Items]
Required Ratio of Indebtedness to Total Capitalization	0.65

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

3 Months Ended

12 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

Federal

^[1]

$ 0.0

State

^[1]

0.7

0.1

Total Current Income Tax Expense

0.7

0.1

Deferred Income Tax Expense (Benefit) [Abstract]

Federal

(6.8)

^[2]

7.3

^[3]

State

2.6

5.9

Investment Tax Credit Amortization

(0.2)

Total Deferred Income Tax Expense (Benefit)

(4.4)

13.0

Total Income Tax Expense (Benefit)

(3.7)

13.1

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

Income Before Non-Controlling Interest and Income Taxes

$ 47.3

$ 62.1

Statutory Federal Income Tax Rate

21.00%

35.00%

Income Taxes Computed at Statutory Federal Rate

$ 9.9

$ 21.7

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

State Income Taxes – Net of Federal Income Tax Benefit

2.6

3.9

Production Tax Credits

(14.4)

(13.0)

Regulatory Differences for Utility Plant

(2.5)

0.1