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☒			Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

or

☐			Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
			For the transition period from ______________ to ______________

Commission File Number 1-3548

(Exact name of registrant as specified in its charter)

Minnesota						41-0418150
(State or other jurisdiction of incorporation or organization)						(IRS Employer Identification No.)

Title of each class			Trading symbol			Name of each exchange on which registered
Common Stock, without par value			ALE			New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   ☒ Yes   ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   ☒ Yes   ☐ No

         Large Accelerated Filer    ☒             Accelerated Filer    ☐

         Non-Accelerated Filer    ☐         Smaller Reporting Company    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ☐ Yes   ☒ No

Definitions									3
Forward-Looking Statements									5
Part I.			Financial Information
			Item 1.			Consolidated Financial Statements - Unaudited			6
						Consolidated Balance Sheet			6
						Consolidated Statement of Income			7
						Consolidated Statement of Comprehensive Income			8
						Consolidated Statement of Cash Flows			9
						Consolidated Statement of Equity			10
						Notes to Consolidated Financial Statements			11
						Note 1. Operations and Significant Accounting Policies			11
						Note 2. Regulatory Matters			13
						Note 3. Equity Investments			17
						Note 4. Fair Value			17
						Note 5. Short-Term and Long-Term Debt			19
						Note 6. Commitments, Guarantees and Contingencies			20
						Note 7. Earnings Per Share and Common Stock			25
						Note 8. Income Tax Expense			26
						Note 9. Pension and Other Postretirement Benefit Plans			27
						Note 10. Business Segments			27
			Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
						Comparison of the Quarters Ended			31
						Comparison of the Nine Months Ended			34
						Critical Accounting Policies			37
						Outlook			38
						Liquidity and Capital Resources			46
						Other			48
			Item 3.			Quantitative and Qualitative Disclosures about Market Risk			49
			Item 4.			Controls and Procedures			49
Part II.			Other Information
			Item 1.			Legal Proceedings			50
			Item 1A.			Risk Factors			50
			Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds			50
			Item 3.			Defaults Upon Senior Securities			50
			Item 4.			Mine Safety Disclosures			50
			Item 5.			Other Information			51
			Item 6.			Exhibits			52
Signatures									53

Abbreviation or Acronym			Term
AFUDC			Allowance for Funds Used During Construction – the cost of both debt and equity funds used to finance regulated utility plant additions during construction periods
ALLETE			ALLETE, Inc.
ALLETE Clean Energy			ALLETE Clean Energy, Inc. and its subsidiaries
ALLETE Properties			ALLETE Properties, LLC and its subsidiaries
ALLETE South Wind			ALLETE South Wind, LLC
ALLETE Transmission Holdings			ALLETE Transmission Holdings, Inc.
ArcelorMittal			ArcelorMittal S.A.
ATC			American Transmission Company LLC
Basin			Basin Electric Power Cooperative, a North Dakota cooperative corporation
Bison			Bison Wind Energy Center
BNI Energy			BNI Energy, Inc. and its subsidiary
Boswell			Boswell Energy Center
Camp Ripley			Camp Ripley Solar Array
Cliffs			Cleveland-Cliffs Inc.
Company			ALLETE, Inc. and its subsidiaries
COVID-19			2019 novel coronavirus
CSAPR			Cross-State Air Pollution Rule
DC			Direct Current
EIS			Environmental Impact Statement
EPA			United States Environmental Protection Agency
ESOP			Employee Stock Ownership Plan
FERC			Federal Energy Regulatory Commission
Form 10-K			ALLETE Annual Report on Form 10-K
Form 10-Q			ALLETE Quarterly Report on Form 10-Q
GAAP			Generally Accepted Accounting Principles in the United States of America
GHG			Greenhouse Gases
GNTL			Great Northern Transmission Line
Hibbing Taconite			Hibbing Taconite Co.
Husky Energy			Husky Energy Inc.
Invest Direct			ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
IRP			Integrated Resource Plan
Item ___			Item ___ of this Form 10-Q
kV			Kilovolt(s)
kW / kWh			Kilowatt(s) / Kilowatt-hour(s)
Laskin			Laskin Energy Center
Lampert Capital Markets			Lampert Capital Markets, Inc.
Manitoba Hydro			Manitoba Hydro-Electric Board
Minnesota Power			An operating division of ALLETE, Inc.
Minnkota Power			Minnkota Power Cooperative, Inc.
MISO			Midcontinent Independent System Operator, Inc.
MMTP			Manitoba-Minnesota Transmission Project
Moody’s			Moody’s Investors Service, Inc.

Abbreviation or Acronym			Term
MPCA			Minnesota Pollution Control Agency
MPUC			Minnesota Public Utilities Commission
MW / MWh			Megawatt(s) / Megawatt-hour(s)
NAAQS			National Ambient Air Quality Standards
NDPSC			North Dakota Public Service Commission
Nobles 2			Nobles 2 Power Partners, LLC
NOL			Net Operating Loss
NOX			Nitrogen Oxides
Northshore Mining			Northshore Mining Company, a wholly-owned subsidiary of Cleveland-Cliffs Inc.
Note ___			Note ___ to the Consolidated Financial Statements in this Form 10-Q
NPDES			National Pollutant Discharge Elimination System
NTEC			Nemadji Trail Energy Center
Oliver Wind I			Oliver Wind I Energy Center
Oliver Wind II			Oliver Wind II Energy Center
PolyMet			PolyMet Mining Corp.
PPA / PSA			Power Purchase Agreement / Power Sales Agreement
PPACA			Patient Protection and Affordable Care Act of 2010
PSCW			Public Service Commission of Wisconsin
SEC			Securities and Exchange Commission
Silver Bay Power			Silver Bay Power Company, a wholly-owned subsidiary of Cleveland-Cliffs Inc.
SO2			Sulfur Dioxide
Square Butte			Square Butte Electric Cooperative, a North Dakota cooperative corporation
South Shore Energy			South Shore Energy, LLC
SWL&P			Superior Water, Light and Power Company
Taconite Harbor			Taconite Harbor Energy Center
Town Center District			Town Center at Palm Coast Community Development District in Florida
U.S.			United States of America
USS Corporation			United States Steel Corporation
WTG			Wind Turbine Generator

•our ability to successfully implement our strategic objectives;

•global and domestic economic conditions affecting us or our customers;

•changes in and compliance with laws and regulations;

•changes in tax rates or policies or in rates of inflation;

•the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;

•weather conditions, natural disasters and pandemic diseases, including the ongoing COVID-19 pandemic;

•our ability to access capital markets, bank financing and other financing sources;

•changes in interest rates and the performance of the financial markets;

•project delays or changes in project costs;

•changes in operating expenses and capital expenditures and our ability to raise revenues from our customers;

•the impacts of commodity prices on ALLETE and our customers;

•our ability to attract and retain qualified, skilled and experienced personnel;

•effects of emerging technology;

•war, acts of terrorism and cybersecurity attacks;

•our ability to manage expansion and integrate acquisitions;

•wholesale power market conditions;

•federal and state regulatory and legislative actions that impact regulated utility economics, including our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities and utility infrastructure, recovery of purchased power, capital investments and other expenses, including present or prospective environmental matters;

•effects of competition, including competition for retail and wholesale customers;

•effects of restructuring initiatives in the electric industry;

•the impacts on our businesses of climate change and future regulation to restrict the emissions of GHG;

•effects of increased deployment of distributed low-carbon electricity generation resources;

•the impacts of laws and regulations related to renewable and distributed generation;

•pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;

•our current and potential industrial and municipal customers’ ability to execute announced expansion plans;

•real estate market conditions where our legacy Florida real estate investment is located may not improve; and

•the success of efforts to realize value from, invest in, and develop new opportunities.

			September 30, 2021						December 31, 2020
Millions
Assets
Current Assets
Cash and Cash Equivalents			$59.0						$44.3
Accounts Receivable (Less Allowance of $2.1 and $2.5)			110.2						111.9
Inventories – Net			89.6						74.2
Prepayments and Other			19.9						24.5
Total Current Assets			278.7						254.9
Property, Plant and Equipment – Net			5,053.1						4,840.8
Regulatory Assets			502.9						480.9
Equity Investments			317.8						301.2
Other Non-Current Assets			179.7						206.8
Total Assets			$6,332.2						$6,084.6
Liabilities and Equity
Liabilities
Current Liabilities
Accounts Payable			$101.9						$110.0
Accrued Taxes			67.4						59.4
Accrued Interest			15.3						19.8
Long-Term Debt Due Within One Year			377.4						203.7
Other			84.0						66.7
Total Current Liabilities			646.0						459.6
Long-Term Debt			1,649.4						1,593.2
Deferred Income Taxes			187.1						195.7
Regulatory Liabilities			509.5						524.8
Defined Benefit Pension and Other Postretirement Benefit Plans			207.6						225.8
Other Non-Current Liabilities			278.1						285.3
Total Liabilities			3,477.7						3,284.4
Commitments, Guarantees and Contingencies (Note 6)
Equity
ALLETE Equity
Common Stock Without Par Value, 80.0 Shares Authorized, 52.6 and 52.1 Shares Issued and Outstanding			1,496.5						1,460.9
Accumulated Other Comprehensive Loss			(29.9)						(31.1)
Retained Earnings			873.4						864.8
Total ALLETE Equity			2,340.0						2,294.6
Non-Controlling Interest in Subsidiaries			514.5						505.6
Total Equity			2,854.5						2,800.2
Total Liabilities and Equity			$6,332.2						$6,084.6

			Quarter Ended									Nine Months Ended
			September 30,									September 30,
			2021			2020						2021			2020
Millions Except Per Share Amounts
Operating Revenue
Contracts with Customers – Utility			$304.8			$255.1						$888.2			$721.2
Contracts with Customers – Non-utility			37.7			35.9						123.4			119.0
Other – Non-utility			2.9			2.9						8.6			8.5
Total Operating Revenue			345.4			293.9						1,020.2			848.7
Operating Expenses
Fuel, Purchased Power and Gas – Utility			140.1			93.4						389.4			251.7
Transmission Services – Utility			19.2			14.9						56.1			49.8
Cost of Sales – Non-utility			15.2			15.4						47.8			48.6
Operating and Maintenance			66.7			61.9						200.1			181.9
Depreciation and Amortization			57.5			53.4						173.4			161.3
Taxes Other than Income Taxes			15.6			13.3						52.1			40.9
Total Operating Expenses			314.3			252.3						918.9			734.2
Operating Income			31.1			41.6						101.3			114.5
Other Income (Expense)
Interest Expense			(17.3)			(16.3)						(51.8)			(47.9)
Equity Earnings			4.4			5.1						14.3			16.7
Other			1.0			2.9						6.1			9.1
Total Other Expense			(11.9)			(8.3)						(31.4)			(22.1)
Income Before Income Taxes			19.2			33.3						69.9			92.4
Income Tax Benefit			(4.9)			(5.5)						(19.3)			(27.8)
Net Income			24.1			38.8						89.2			120.2
Net Loss Attributable to Non-Controlling Interest			(3.5)			(1.9)						(18.1)			(6.9)
Net Income Attributable to ALLETE			$27.6			$40.7						$107.3			$127.1
Average Shares of Common Stock
Basic			52.4			51.9						52.3			51.8
Diluted			52.5			52.0						52.3			51.9
Basic Earnings Per Share of Common Stock			$0.53			$0.78						$2.05			$2.45
Diluted Earnings Per Share of Common Stock			$0.53			$0.78						$2.05			$2.45

			Quarter Ended												Nine Months Ended
			September 30,												September 30,
			2021						2020						2021						2020
Millions
Net Income			$24.1						$38.8						$89.2						$120.2
Other Comprehensive Income
Defined Benefit Pension and Other Postretirement Benefit Plans
Net of Income Tax Expense of $0.1, $0.1, $0.4 and $0.2			0.4						0.2						1.2						0.5
Total Other Comprehensive Income			0.4						0.2						1.2						0.5
Total Comprehensive Income			24.5						39.0						90.4						120.7
Net Loss Attributable to Non-Controlling Interest			(3.5)						(1.9)						(18.1)						(6.9)
Total Comprehensive Income Attributable to ALLETE			$28.0						$40.9						$108.5						$127.6

			Nine Months Ended
			September 30,
			2021						2020
Millions
Operating Activities
Net Income			$89.2						$120.2
AFUDC – Equity			(1.7)						(1.8)
Income from Equity Investments – Net of Dividends			1.8						(2.3)
Gain on Investments and Property, Plant and Equipment			(0.7)						—
Depreciation Expense			173.4						161.3
Amortization of PSAs			(8.6)						(8.5)
Amortization of Other Intangible Assets and Other Assets			7.4						7.5
Deferred Income Tax Benefit			(19.4)						(27.9)
Share-Based and ESOP Compensation Expense			4.6						4.7
Defined Benefit Pension and Postretirement Benefit Expense			3.3						0.1
Provision for Interim Rate Refund			—						5.2
Payments for Tax Reform Refund			—						(0.1)
Bad Debt Expense			0.9						1.6
Changes in Operating Assets and Liabilities
Accounts Receivable			0.8						2.8
Inventories			(15.4)						(2.0)
Prepayments and Other			7.9						8.8
Accounts Payable			4.0						2.2
Other Current Liabilities			20.7						12.5
Cash Contributions to Defined Benefit Pension Plans			(10.3)						(10.7)
Changes in Regulatory and Other Non-Current Assets			(41.3)						(23.5)
Changes in Regulatory and Other Non-Current Liabilities			(7.4)						(8.2)
Cash from Operating Activities			209.2						241.9
Investing Activities
Proceeds from Sale of Available-for-sale Securities			3.3						6.8
Payments for Purchase of Available-for-sale Securities			(3.0)						(7.2)
Payments for Equity Method Investments			(17.4)						(91.0)
Additions to Property, Plant and Equipment			(384.3)						(540.8)
Other Investing Activities			4.3						1.0
Cash for Investing Activities			(397.1)						(631.2)
Financing Activities
Proceeds from Issuance of Common Stock			31.0						12.8
Proceeds from Issuance of Short-Term and Long-Term Debt			510.6						607.4
Repayments of Short-Term and Long-Term Debt			(280.9)						(207.4)
Proceeds from Non-Controlling Interest in Subsidiaries			28.9						67.8
Dividends on Common Stock			(98.7)						(96.0)
Other Financing Activities			(2.8)						(2.7)
Cash from Financing Activities			188.1						381.9
Change in Cash, Cash Equivalents and Restricted Cash			0.2						(7.4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period			65.2						92.5
Cash, Cash Equivalents and Restricted Cash at End of Period			$65.4						$85.1

			Quarter Ended									Nine Months Ended
			September 30,									September 30,
			2021			2020						2021			2020
Millions Except Per Share Amounts
Common Stock
Balance, Beginning of Period			$1,474.1			$1,447.7						$1,460.9			$1,436.7
Common Stock Issued			22.4			6.5						35.6			17.5
Balance, End of Period			1,496.5			1,454.2						1,496.5			1,454.2
Accumulated Other Comprehensive Loss
Balance, Beginning of Period			(30.3)			(23.3)						(31.1)			(23.6)
Other Comprehensive Income - Net of Income Taxes
Defined Benefit Pension and Other Postretirement Plans			0.4			0.2						1.2			0.5
Balance, End of Period			(29.9)			(23.1)						(29.9)			(23.1)
Retained Earnings
Balance, Beginning of Period			878.8			841.3						864.8			818.8
Net Income Attributable to ALLETE			27.6			40.7						107.3			127.1
Common Stock Dividends			(33.0)			(32.1)						(98.7)			(96.0)
Balance, End of Period			873.4			849.9						873.4			849.9
Non-Controlling Interest in Subsidiaries
Balance, Beginning of Period			519.3			166.5						505.6			103.7
Proceeds from Non-Controlling Interest in Subsidiaries			—			—						28.9			67.8
Net Loss Attributable to Non-Controlling Interest			(3.5)			(1.9)						(18.1)			(6.9)
Distributions to Non-Controlling Interest			(1.3)			—						(1.9)			—
Balance, End of Period			514.5			164.6						514.5			164.6
Total Equity			$2,854.5			$2,445.6						$2,854.5			$2,445.6
Dividends Per Share of Common Stock			$0.63			$0.6175						$1.89			$1.8525

Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. As of September 30, 2021, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under ALLETE Clean Energy loan and tax equity financing agreements as well as PSAs. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amounts presented in the Consolidated Statement of Cash Flows.

Cash, Cash Equivalents and Restricted Cash			September 30, 2021						December 31, 2020						September 30, 2020						December 31, 2019
Millions
Cash and Cash Equivalents			$59.0						$44.3						$79.0						$69.3
Restricted Cash included in Prepayments and Other			4.1						0.8						3.2						2.8
Restricted Cash included in Other Non-Current Assets			2.3						20.1						2.9						20.4
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows			$65.4						$65.2						$85.1						$92.5

Inventories – Net. 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 ALLETE Clean Energy segment and Corporate and Other businesses are carried at an average cost, first-in, first-out or specific identification basis.

Inventories – Net			September 30, 2021						December 31, 2020
Millions
Fuel (a)			$12.4						$23.1
Materials and Supplies			55.2						51.1
Construction of Wind Energy Facilities (b)			22.0						—
Total Inventories – Net			$89.6						$74.2

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

(b) Project costs related to ALLETE Clean Energy’s Northern Wind and Red Barn wind projects which are expected be sold in late 2022. (See Other Current Liabilities.)

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets			September 30, 2021						December 31, 2020
Millions
Contract Assets (a)			$23.4						$25.5
Operating Lease Right-of-use Assets			17.7						22.4
ALLETE Properties			17.6						18.2
Restricted Cash			2.3						20.1
Other Postretirement Benefit Plans			35.8						34.2
Other			82.9						86.4
Total Other Non-Current Assets			$179.7						$206.8

(a)    Contract Assets consist of 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 as a reduction to revenue.     

Other Current Liabilities			September 30, 2021						December 31, 2020
Millions
Customer Deposits (a)			$27.5						$7.4
PSAs			12.6						12.5
Fuel Adjustment Clause			2.6						3.7
Operating Lease Liabilities			5.0						5.9
Other			36.3						37.2
Total Other Current Liabilities			$84.0						$66.7

(a) Primarily related to deposits received by ALLETE Clean Energy for the Northern Wind and Red Barn wind projects which are expected be sold in late 2022. (See Inventories – Net.)

Other Non-Current Liabilities			September 30, 2021						December 31, 2020
Millions
Asset Retirement Obligation (a)			$170.9						$166.6
PSAs			42.6						52.1
Operating Lease Liabilities			12.7						16.5
Other			51.9						50.1
Total Other Non-Current Liabilities			$278.1						$285.3

(a)The asset retirement obligation is primarily related to our Regulated Operations and is funded through customer rates over the life of the related assets. Additionally, BNI Energy funds its obligation through its cost-plus coal supply agreements for which BNI Energy has recorded a receivable of $25.0 million in Other Non-Current Assets on the Consolidated Balance Sheet as of September 30, 2021, and December 31, 2020.

Other Income
Nine Months Ended September 30,			2021			2020
Millions
Pension and Other Postretirement Benefit Plan Non-Service Credits (a)			$4.4			$6.5
Interest and Investment Income			1.7			0.4
AFUDC - Equity			1.7			1.8
Other			(1.7)			0.4
Total Other Income			$6.1			$9.1

(a)These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 9. Pension and Other Postretirement Benefit Plans.)

Nine Months Ended September 30,			2021						2020
Millions
Cash Paid for Interest – Net of Amounts Capitalized			$54.9						$48.8
Noncash Investing and Financing Activities
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment			$(12.1)						$(88.4)
Capitalized Asset Retirement Costs			$3.5						$2.1
AFUDC–Equity			$1.7						$1.8

Non-Controlling Interest in Subsidiaries. Non-controlling interest in subsidiaries on the Consolidated Balance Sheet and net loss attributable to non-controlling interest on the Consolidated Statement of Income represent the portion of equity ownership and earnings, respectively, of subsidiaries that are not attributable to equity holders of ALLETE. These amounts are primarily related to the tax equity financing structures for ALLETE Clean Energy’s 106 MW Glen Ullin, 80 MW South Peak and 303 MW Diamond Spring wind energy facilities as well as ALLETE’s equity investment in the 250 MW Nobles 2 wind energy facility.

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

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. Revenue from cost recovery riders was $29.2 million for the nine months ended September 30, 2021 ($22.6 million for the nine months ended September 30, 2020).

2020 Minnesota General Rate Case. In November 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing sought a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $66 million in additional revenue. In December 2019 orders, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $36.1 million beginning January 1, 2020.

2022 Minnesota General Rate Case. On November 1, 2021, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 18 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $108 million in additional revenue. Once the filing is accepted as complete, an annual interim rate increase of approximately $87 million, subject to refund, which would be an average increase of approximately 14 percent for retail customers, is expected to be implemented within 60 days, subject to MPUC adjustment and authorization. We cannot predict the level of interim or final rates that may be authorized by the MPUC.

Minnesota Power Land Sales. In August 2020, Minnesota Power filed a petition with the MPUC for approval to sell land that surrounds several reservoirs on its hydroelectric system and is no longer required to maintain its operations. The land has an estimated value of approximately $100 million, and Minnesota Power proposed to credit ratepayers the net proceeds from the sales in a future rate case or through its renewable resources rider to mitigate future rate increases. At a hearing on October 14, 2021, the MPUC decided to allow the land sales to occur and the proceeds refunded to ratepayers subject to certain conditions and required compliance filings.

Electric Vehicle Charging Infrastructure Petition. On April 8, 2021, Minnesota Power filed a petition seeking approval to install and own DC fast charger stations for electric vehicles across its service territory, implement accompanying rates for those stations, and track and recover investments and expenses for the project. In an order dated October 22, 2021, the MPUC approved Minnesota Power’s petition.

Conservation Improvement Program. On April 1, 2021, Minnesota Power submitted its 2020 consolidated filing detailing Minnesota Power’s CIP program results and requesting a CIP financial incentive of $2.4 million based upon MPUC procedures, which was recognized in the third quarter of 2021 upon approval by the MPUC in an order dated September 7, 2021. In 2020, a CIP financial incentive of $2.4 million was recognized in the third quarter upon approval by the MPUC of Minnesota Power’s 2019 CIP consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

2021 Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP with the MPUC, which outlines its clean-energy transition plans through 2035. These plans include expanding its renewable energy supply, achieving coal-free operations at its facilities by 2035, and investing in a resilient and flexible transmission and distribution grid. As part of these plans, Minnesota Power anticipates adding approximately 400 MW of new wind and solar energy resources, retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Minnesota Power’s plans recognize that advances in technology will play a significant role in completing its transition to carbon-free energy supply, reliably and affordably. A final decision on the IRP is expected in mid-2022.

Nemadji Trail Energy Center. In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of a natural gas capacity dedication and other affiliated-interest agreements for NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to the capacity dedication agreement. (See Note 1. Operations and Significant Accounting Policies – Subsequent Events.) In a January 2019 order, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication and other affiliated-interest agreements. In 2019, the Minnesota Court of Appeals reversed and remanded the MPUC’s decision to approve certain affiliated-interest agreements. On April 21, 2021, the Minnesota Supreme Court reversed the Minnesota Court of Appeal’s decision by ruling that the MPUC is not required to conduct a review under the Minnesota Environmental Policy Act before approving affiliated-interest agreements that govern construction and operation of a Wisconsin power plant by a Minnesota utility, and remanded the case back to the Minnesota Court of Appeals for review of remaining issues on appeal. On August 23, 2021, the Minnesota Court of Appeals affirmed the decision by the MPUC to approve certain affiliated-interest agreements.

Verso Corporation Electric Service Agreement. On August 2, 2021, Minnesota Power filed a petition with the MPUC requesting the MPUC to interpret the electric service agreement (ESA) between Minnesota Power and Verso Corporation finding that Verso Corporation has tariff obligations and owes minimum firm demand payments during the term of the ESA. Minnesota Power filed this petition in response to Verso Corporation ceasing to make its minimum firm demand payments under the ESA. At a hearing on October 14, 2021, the MPUC agreed with Minnesota Power’s petition and concluded that the MPUC has jurisdiction to interpret the relevant provisions of the ESA, and the ESA requires Verso Corporation to continue full minimum firm demand payments for a period of two years from the January 29, 2021, notice of termination, regardless of Minnesota Power’s electricity sales to a new customer at the former Verso Corporation facility. Minnesota Power has a receivable related to the ESA of approximately $1.2 million as of September 30, 2021. In addition, Verso Corporation owes Minnesota Power payments under a steam agreement, which is proceeding through arbitration. Minnesota Power has a receivable under the steam agreement of approximately $2.4 million as of September 30, 2021. Minnesota Power expects to fully collect these outstanding account receivable balances as well as Verso Corporation’s remaining obligations under the ESA.

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. With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

Regulatory Assets and Liabilities			September 30, 2021						December 31, 2020
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans			$247.6						$259.7
Income Taxes			107.2						113.7
Cost Recovery Riders			61.8						54.0
Asset Retirement Obligations			31.4						31.6
Fuel Adjustment Clause			30.1						—
Manufactured Gas Plant			11.9						8.8
PPACA Income Tax Deferral			4.4						4.5
Boswell Units 1 and 2 Net Plant and Equipment			3.2						5.0
Other			5.3						3.6
Total Non-Current Regulatory Assets			$502.9						$480.9
Current Regulatory Liabilities (a)
Fuel Adjustment Clause			$2.6						$3.7
Transmission Formula Rates Refund			3.1						2.9
Other			3.3						1.0
Total Current Regulatory Liabilities			9.0						7.6
Non-Current Regulatory Liabilities
Income Taxes			359.3						375.3
Wholesale and Retail Contra AFUDC			84.4						86.6
Plant Removal Obligations			47.4						41.2
North Dakota Investment Tax Credits			12.3						12.0
Defined Benefit Pension and Other Postretirement Benefit Plans			1.4						4.4
Conservation Improvement Program			—						1.5
Other			4.7						3.8
Total Non-Current Regulatory Liabilities			509.5						524.8
Total Regulatory Liabilities			$518.5						$532.4

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

ALLETE’s Investment in ATC
Millions
Equity Investment Balance as of December 31, 2020			$149.0
Equity in ATC Earnings			15.8
Distributed ATC Earnings			(12.8)
Amortization of the Remeasurement of Deferred Income Taxes			1.0
Equity Investment Balance as of September 30, 2021			$153.0

Investment in Nobles 2. Our subsidiary, ALLETE South Wind, owns 49 percent of Nobles 2, the entity that owns and operates the 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. We account for our investment in Nobles 2 under the equity method of accounting.

ALLETE’s Investment in Nobles 2
Millions
Equity Investment Balance as of December 31, 2020			$152.2
Cash Investments			17.4
Equity in Nobles 2 Earnings (a)			(1.5)
Distributed Nobles 2 Earnings			(3.3)
Equity Investment Balance as of September 30, 2021			$164.8

(a)The Company also recorded net loss attributable to non-controlling interest of $4.4 million related to its investment in Nobles 2.

			Fair Value as of September 30, 2021
Recurring Fair Value Measures			Level 1						Level 2						Level 3						Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities			$9.2						—						—						$9.2
Available-for-sale – Corporate and Governmental Debt Securities (b)			—						$8.4						—						8.4
Cash Equivalents			2.8						—						—						2.8
Total Fair Value of Assets			$12.0						$8.4						—						$20.4
Liabilities
Deferred Compensation (c)			—						$21.5						—						$21.5
Total Fair Value of Liabilities			—						$21.5						—						$21.5
Total Net Fair Value of Assets (Liabilities)			$12.0						$(13.1)						—						$(1.1)
			Fair Value as of December 31, 2020
Recurring Fair Value Measures			Level 1						Level 2						Level 3						Total
Millions
Assets
Investments (a)
Available-for-sale – Equity Securities			$7.2						—						—						$7.2
Available-for-sale – Corporate and Governmental Debt Securities			—						$10.4						—						10.4
Cash Equivalents			5.5						—						—						5.5
Total Fair Value of Assets			$12.7						$10.4						—						$23.1
Liabilities
Deferred Compensation (c)			—						$21.0						—						$21.0
Total Fair Value of Liabilities			—						$21.0						—						$21.0
Total Net Fair Value of Assets (Liabilities)			$12.7						$(10.6)						—						$2.1

(b)As of September 30, 2021, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.5 million, in one year to less than three years was $3.4 million, in three years to less than five years was $3.0 million and in five or more years was $0.5 million.

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 of 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
Short-Term and Long-Term Debt (a)
September 30, 2021			$2,036.1						$2,262.2
December 31, 2020			$1,806.4						$2,122.0

(a)Excludes unamortized debt issuance costs.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, land inventory, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized. For the quarter and nine months ended September 30, 2021, and the year ended December 31, 2020, there were no indicators of impairment for these non-financial assets.

September 30, 2021			Principal						Unamortized Debt Issuance Costs						Total
Millions
Short-Term Debt			$377.6						$(0.2)						$377.4
Long-Term Debt			1,658.5						(9.1)						1,649.4
Total Debt			$2,036.1						$(9.3)						$2,026.8

December 31, 2020			Principal						Unamortized Debt Issuance Costs						Total
Millions
Short-Term Debt			$204.0						$(0.3)						$203.7
Long-Term Debt			1,602.4						(9.2)						1,593.2
Total Debt			$1,806.4						$(9.5)						$1,796.9

On March 25, 2021, ALLETE entered into a $150 million unsecured term loan agreement (Term Loan). An additional draw of $35 million through the exercise of an accordion feature was made during the second quarter of 2021. As of September 30, 2021, we have borrowed the full amount of $185 million. The Term Loan is due March 24, 2022, and may be repaid at any time. Interest is payable monthly at a rate per annum equal to LIBOR plus 0.75 percent. Proceeds from the Term Loan were used for general corporate purposes.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of September 30, 2021, our ratio was approximately 0.43 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of September 30, 2021, ALLETE was in compliance with its financial covenants.

Power Purchase and Sale 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.

Square Butte PPA. As of September 30, 2021, Square Butte had total debt outstanding of $256.9 million. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract. Minnesota Power’s cost of power purchased from Square Butte during the nine months ended September 30, 2021, was $60.3 million ($59.9 million for the same period in 2020). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $4.3 million ($5.4 million for the same period in 2020). 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, Minnesota Power sold to Minnkota Power approximately 28 percent in 2021 and in 2020.

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 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2021. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s retail and municipal utility customers through the fuel adjustment clause.

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s thermal 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 NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.

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 NOX and SO2 allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. The EPA’s CSAPR Update Rule issued on March 15, 2021, to revise the 2016 CSAPR Update does not apply to the state of Minnesota and is therefore not currently projected to affect Minnesota Power’s CSAPR compliance. The State of Minnesota has not been identified in litigation as a culpable upwind emission source to downwind states, and previous EPA air quality modeling has demonstrated that Minnesota is not a significant contributor to downwind air quality attainment challenges. Minnesota Power will continue to monitor ongoing CSAPR rulemakings and compliance implementation.

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. Minnesota Power actively monitors NAAQS developments and compliance costs for existing standards or proposed NAAQS revisions are not currently expected to be material. The EPA is currently reviewing the secondary NAAQS for NOx and SO2, as well as particulate matter. On June 10, 2021, the EPA announced it will reconsider the December 2020 final rule retaining the 2012 particulate matter NAAQS, with a proposed rulemaking anticipated in mid-2022. The EPA has not stated its intent with regard to the 2020 Ozone NAAQS rule finalized in December 2020.

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 or other changes in 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 renewable power supply for both our operations and the operations of others;

•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;

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

•Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and

•Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species.

EPA Regulation of GHG Emissions. In 2019, the EPA finalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units. These rulemakings included repealing the Clean Power Plan (CPP) and adopting the Affordable Clean Energy Rule under Section 111(d) of the Clean Air Act (CAA) to regulate CO2 emissions at existing coal-fired power plants. The CPP was first announced as a proposed rule under Section 111(d) of the CAA for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”. The Affordable Clean Energy Rule established emissions guidelines for states to use when developing plans to limit CO2 coal-fired power plants. The EPA also published regulations for the state implementation of the Affordable Clean Energy Rule and other Section 111(d) rules. Affected facilities for Minnesota Power included Boswell Units 3 and 4, and Taconite Harbor Units 1 and 2, which are currently economically idled.

Additionally on January 13, 2021, the EPA issued a rulemaking to apply CO2 emission New Source Performance Standards (NSPS) to new, modified and reconstructed fossil fuel-fired electric generating units under Section 111(b) of the CAA. Minnesota Power is monitoring the NSPS final rule and any further Section 111(b) developments including their potential impact to the Company. The Company’s proposed combined-cycle natural gas-fired generating facility, NTEC, is expected to meet these NSPS requirements.

Water. The Clean Water Act requires NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.

Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation 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 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsidered the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On October 13, 2020, the EPA published a final ELG Rule allowing re-use of bottom ash transport water in FGD scrubber systems with limited discharges related to maintaining system water balance. The rule sets technology standards and numerical pollutant limits for discharges of bottom ash transport water and FGD wastewater. Compliance deadlines depend on subcategory, with compliance generally required as soon as possible, beginning after October 13, 2021, but no later than December 31, 2025, or December 31, 2028, in some specific cases. The rule also established new subcategories for retiring high-flow and low-utilization units, and established a voluntary incentives program for FGD wastewater. In accordance with the January 2021 Executive Order 13990, the EPA was mandated to conduct a review of actions and polices taken during the prior administration, including the 2020 ELG Rule. On September 14, 2021, the EPA published a notice of availability for preliminary effluent guidelines program plan. In the plan, the EPA confirmed the agency is initiating a rulemaking process to strengthen wastewater pollution limitations from FGD and bottom ash transport water discharges while the 2020 ELG Rule remains in effect. The EPA is expected to publish a proposed rule in the fall of 2022.

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 produces the majority of its coal ash at Boswell, with small amounts of ash generated at Hibbard Renewable Energy Center. Ash storage and disposal methods include storing ash in clay-lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, 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 be incurred primarily over the next 15 years and be between approximately $65 million and $120 million. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

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. As of September 30, 2021, we have recorded a liability of approximately $13 million for remediation costs at this site after incorporating detailed design components specific to the site (approximately $7 million as of December 31, 2020); however, SWL&P continues to work with the WDNR on the extent of contamination which may result in additional remediation costs being identified. SWL&P has also recorded an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. Remediation costs are expected to be incurred through 2023.

Regulated Operations. As of September 30, 2021, we had $4.9 million outstanding in standby letters of credit at our Regulated Operations which are pledged as security to MISO and a state agency.

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 2022 and 2039. As of September 30, 2021, ALLETE Clean Energy has $81.9 million outstanding in standby letters of credit, the majority of which are pledged as security under these PSAs and PSAs for wind energy facilities under development. ALLETE Clean Energy does not believe it is likely that any of these outstanding letters of credit will be drawn upon.

South Shore Energy. As of September 30, 2021, South Shore Energy had $23.9 million outstanding in standby letters of credit pledged as security in connection with the development of NTEC. South Shore Energy does not believe it is likely that any of these outstanding letters of credit will be drawn upon.

Investment in Nobles 2. The Nobles 2 wind energy facility requires standby letters of credit as security for certain contractual obligations. As of September 30, 2021, ALLETE South Wind has $13.2 million outstanding in standby letters of credit, related to its portion of the security requirements relative to its ownership in Nobles 2. We do not believe it is likely that any of these outstanding letters of credit will be drawn upon.

Community Development District Obligations. As of September 30, 2021, we owned 48 percent of the assessable land in the Town Center District (48 percent as of December 31, 2020). As of September 30, 2021, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $1.8 million. As we sell property at this project, 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.

									2021																		2020
Reconciliation of Basic and Diluted									Dilutive																		Dilutive
Earnings Per Share			Basic						Securities						Diluted						Basic						Securities						Diluted
Millions Except Per Share Amounts
Quarter ended September 30,
Net Income Attributable to ALLETE			$27.6												$27.6						$40.7												$40.7
Average Common Shares			52.4						0.1						52.5						51.9						0.1						52.0
Earnings Per Share			$0.53												$0.53						$0.78												$0.78
Nine Months Ended September 30,
Net Income Attributable to ALLETE			$107.3												$107.3						$127.1												$127.1
Average Common Shares			52.3						—						52.3						51.8						0.1						51.9
Earnings Per Share			$2.05												$2.05						$2.45												$2.45

						Quarter Ended												Nine Months Ended
						September 30,												September 30,
						2021						2020						2021						2020
Millions
Current Income Tax Expense (a)
Federal						—						—						—						—
State						$0.1						$0.1						$0.1						$0.1
Total Current Income Tax Expense						$0.1						$0.1						$0.1						$0.1
Deferred Income Tax Expense (Benefit)
Federal (b)						$(5.8)						$(8.3)						$(26.3)						$(34.5)
State						0.9						2.9						7.3						7.1
Investment Tax Credit Amortization						(0.1)						(0.2)						(0.4)						(0.5)
Total Deferred Income Tax Benefit						$(5.0)						$(5.6)						$(19.4)						$(27.9)
Total Income Tax Benefit						$(4.9)						$(5.5)						$(19.3)						$(27.8)

(a)For each of the three and nine months ended September 30, 2021 and 2020, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of certain tax legislation. Federal and state NOLs are being carried forward to offset current and future taxable income.

(b)For each of the three and nine months ended September 30, 2021 and 2020, the federal income tax benefit is primarily due to production tax credits.

			Quarter Ended									Nine Months Ended
Reconciliation of Taxes from Federal Statutory			September 30,									September 30,
Rate to Total Income Tax Expense			2021						2020			2021						2020
Millions
Income Before Income Taxes			$19.2						$33.3			$69.9						$92.4
Statutory Federal Income Tax Rate			21		%				21		%	21		%				21		%
Income Taxes Computed at Statutory Federal Rate			$4.0						$7.0			$14.7						$19.4
Increase (Decrease) in Income Tax Due to:
State Income Taxes (Credit) – Net of Federal Income Tax Benefit			0.7						2.4			5.8						5.7
Production Tax Credits			(9.5)						(12.5)			(36.6)						(45.9)
Regulatory Differences – Excess Deferred Tax			(2.1)						(3.2)			(6.7)						(8.5)
Non-Controlling Interest in Subsidiaries			0.8						0.4			3.9						1.5
Share-Based Compensation			—						—			0.5						(0.1)
Other			1.2						0.4			(0.9)						0.1
Total Income Tax Benefit			$(4.9)						$(5.5)			$(19.3)						$(27.8)

Uncertain Tax Positions. As of September 30, 2021, we had gross unrecognized tax benefits of $1.5 million ($1.4 million as of December 31, 2020). Of the total gross unrecognized tax benefits, $0.6 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.

			Pension												Other Postretirement
Components of Net Periodic Benefit Cost (Credit)			2021						2020						2021						2020
Millions
Quarter Ended September 30,
Service Cost			$2.7						$2.7						$0.9						$0.8
Non-Service Cost Components (a)
Interest Cost			6.1						6.9						1.1						1.2
Expected Return on Plan Assets			(10.8)						(10.6)						(2.4)						(2.4)
Amortization of Prior Service Credits			—						—						(1.9)						(2.0)
Amortization of Net Loss			4.7						3.2						0.7						0.3
Net Periodic Benefit Cost (Credit)			$2.7						$2.2						$(1.6)						$(2.1)
Nine Months Ended September 30,
Service Cost			$8.2						$8.0						$2.7						$2.5
Non-Service Cost Components (a)
Interest Cost			18.4						20.9						3.3						3.7
Expected Return on Plan Assets			(32.5)						(32.0)						(7.3)						(7.3)
Amortization of Prior Service Credits			(0.1)						(0.1)						(5.7)						(6.0)
Amortization of Net Loss			14.1						9.6						2.2						0.8
Net Periodic Benefit Cost (Credit)			$8.1						$6.4						$(4.8)						$(6.3)